Well treatment compositions and methods comprising certain microemulsions and certain clay control additives exhibiting synergistic effect of enhancing clay swelling protection and persistency

ABSTRACT

Compositions and methods comprising certain microemulsions and certain clay control additives for enhancing clay swelling protection and persistency in treating swelling clay of a subterranean formation of oil and/or gas wells are generally provided. The combination of certain microemulsions and certain clay control additives exhibit synergistic effects by enhancing clay swelling protection and persistency in treating swelling clay. The well treatment composition may use up to four times less concentration of clay control additive compared to using the same clay control additive alone, while still providing the same, similar, or higher degree of clay swelling protection and enhanced persistency. The microemulsion and the clay control additive may be added to a carrier fluid to form the well treatment composition, which is injected into the subterranean formation to provide enhanced clay swelling protection and persistency of continuing to provide clay swelling protection for a longer period of time during flowback.

TECHNICAL FIELD

Compositions and methods comprising certain microemulsions and certainclay control additives to treat clay present in a subterranean formationof oil and/or gas wells are generally described.

BACKGROUND

The energy shift towards shale gas is a key factor leading to the growthof horizontal (e.g. unconventional) well hydraulic fracturing and hencethe fracturing fluid market. The world's fracturing fluids market isexpected to triple by the next decade. The oil and gas industry,however, has experienced cost constraints and shrinking margins inrecent years, calling for the immediate need for productivity andefficiency improvements. One area that may need productivity andefficiency improvements is in the use of more efficient (e.g., higherperforming or better performing) clay control additives for treating theproblems associated with clay or clay minerals found in mostsubterranean formations (sometimes referred to as rock formations).

Most of the subterranean hydrocarbon-bearing shale formations containlarge amounts of clay or clay minerals. The presence of clay or clayminerals can cause damage to the subterranean formation during oiland/or gas well treatment operations, which can sometimes result in asignificant reduction of oil and/or gas production or even a completeloss of oil and/or gas production. Damage to the subterranean formation,which may also be referred to as subterranean formation damage orformation damage, refers to any process that causes a reduction in thenatural inherent productivity of an oil or gas producing formation thattend to decrease pore volume and effective permeability of the producingformation. Damage can occur near the wellbore face or deep into thesubterranean formation. In some cases, formation damage may includeemulsion and water blocks, asphaltene and paraffin deposition,condensate banking, and fine migration.

The most common problematic clays for the oil and gas industry arekaolinite, illite, chlorite, smectite, and mixed layers of smectite andillite. Clays have a large surface area and contain a significant amountof negatively charged sites which increase their water sensitivity.Clays can be classified as swelling clay or non-swelling clay. Smectiteis the only clay that swells by absorbing water between its sheets.Mixed layer clays which comprise smectite and illite may also swell.Kaolinite and illite are classified as non-swelling clays.

When aqueous well treatment fluids are introduced into the subterraneanformation, some clays such as smectite can swell, increasing theiroriginal volume by several times. The expansion or swelling of the clayis known as clay swelling. When clay swelling occurs, the clay may plugpore throats (sometimes referred to simply as “pores”) of reservoirrocks, which adversely prevents or reduces the ability of oil and/or gasto flow out of the formation of the reservoir, thereby reducinghydrocarbon production as well as causing formation damage to thereservoir. Clays, including swelling clays, comprise negatively chargedmica-like sheets, which are held together by cations, typically sodiumor calcium for example. Upon contact with fresh water or water having alow salinity, these cations are solubilized resulting in the interlayerregions of the clay to expand readily, which promotes instability,resulting in clay swelling. The term clay swelling comprises clays whichswell, disperse, disintegrate or otherwise become instable, exhibitingan increase in bulk volume when treated in the presence of aqueous welltreatment fluids such as stimulation fluids, drilling fluids, workoverfluids etc.

As stated above, clays may have a significant amount of negative chargesand may be stabilized by inorganic salts such as potassium chloride(KCl), sodium chloride (NaCl) and ammonium chloride (NH₄Cl). Althoughseveral inorganic salts can be used, potassium chloride (KCl) is themost commonly used salt in the oil and gas industry and is usually usedas a reference to select efficient clay control additives in enhancingclay swelling protection (e.g. in reducing or preventing clay swellingof swelling clays) for clay control treatment operations. In addition toinorganic salts, other clay control additives, such as small moleculequaternary amines (e.g., choline chloride and tetramethyl ammoniumchloride), can be used.

Generally, temporary clay control additives (e.g., inorganic saltsand/or small molecule quaternary amines) comprise cations, which arecontained within the inorganic salt and/or the small molecule quaternaryamines, and are attracted to the negative sites to replace thesolubilized sodium or calcium cations through cation exchange. Withoutwishing to be bound by theory, the mechanism of cation exchangerestricts the adsorption of additional water between the clay sheets.The cations (e.g., sodium or calcium) are themselves quickly replaced,after, for example: (1) the well treatment is completed; and/or (2) thewell is placed into production and the original well treatment fluid isdisplaced-which may result in clay swelling and eventually damage to thesubterranean formation.

Generally, permanent clay control additives such as low molecularweight, cationic polymers, are able to resist removal by subsequent acidtreatments and/or flowback. Permanent clay control additives can reduceor prevent clay swelling of swelling clays, because they may containseveral cationic sites available in their polymer backbone, which areadsorbed simultaneously to the clay surfaces. The probability ofdesorption occurring is significantly reduced, hence the permanent clayprotection that the clay control additives provide. However, at higherdosages, permanent clay control additives can cause formation damage dueto their polymeric nature. Because of the significant amount of bondingon the clay surfaces, permanent clay control additives cannot be removedvia cation exchange that occurs with temporary clay control additives.

Microemulsions may also be added to a fracturing fluid, and they arecommonly employed in a variety of oil and/or gas well treatmentoperations related to the extraction of hydrocarbons (e.g., oil and/orgas), such as well stimulation. Low porosity, tight subterraneanformations must be stimulated to improve recovery of hydrocarbons fromthe well. Common stimulation techniques include hydraulic fracturing.Hydraulic fracturing consists of the high pressure injection of afracturing fluid containing suspended proppant into the wellbore inorder to create fractures in the subterranean formation and facilitateproduction from low permeability zones. All chemical additives pumpeddownhole in an oil and/or gas well can filter through the reservoir rockand potentially block pore throats, with the possibility of creatingformation damage. Fluid invasion may significantly reduce hydrocarbonproduction from a well. In order to reduce fluid invasion,microemulsions are generally added to the well treatment fluids to helpunload the residual aqueous treatment from the formation to increaseflowback. As used herein, the term flowback generally refers to theprocess of allowing fluids to flow from the reservoir after a welltreatment.

Microemulsions have several applications in well treatments (e.g.,remediation, stimulation, hydraulic fracturing, enhanced oil recovery(EOR) and improved oil recovery (IOR) operations). In a subterraneanformation, capillary pressure is equivalent to the pressure required forthe hydrocarbon to force water out of the pores of the subterraneanformation. Water that remains in the pores near the wellbore forms awater block that may prevent the flow of hydrocarbon into the well.Microemulsions may lower the capillary pressure of the water in thepores of the subterranean formation, which may in turn decrease theformation of undesirable water blocks in the wellbore. It is believedthat lower capillary pressure increases flowback, which allows morehydrocarbon to flow freely out of the subterranean formation, which maythen be produced and recovered.

While clay control additives and microemulsion additives have beenindividually explored, the use of these additives in tandem,specifically their synergistic effects, have yet to be fully explored.Accordingly, new compositions and methods are desired.

SUMMARY

The subject matter of the present invention involves, in some cases,interrelated products, alternative solutions to a particular problem,and/or a plurality of different uses of one or more systems and/orarticles.

In one aspect, a method of treating a subterranean formation of an oiland/or gas well using a well treatment composition is provided. Themethod may comprise injecting a well treatment composition into asubterranean formation, the well treatment composition comprising amicroemulsion from 75 wt % to 90 wt % versus the total weight of thewell treatment composition, wherein the microemulsion comprises anaqueous phase from 10 wt % to 50 wt %, versus the total weight of themicroemulsion, a surfactant from 10 wt % to 40 wt %, versus the totalweight of the microemulsion, and a solvent from 5 wt % and 25 wt %,versus the total weight of the microemulsion, wherein the solvent is aterpene solvent. The well treatment composition may also comprise a claycontrol additive from 10 wt % to 25 wt % versus the total weight of thewell treatment composition, wherein the clay control additive comprises30 wt % to 90 wt % water, versus the total weight of the clay controladditive, and a clay control compound from 10 wt % to 70 wt %, versusthe total weight of the clay control additive, wherein the clay controlcompound comprises a cationic polymer, and wherein the cationic polymercomprises a polyquaternary amine. In some embodiments, the welltreatment composition further comprises a carrier fluid, wherein themicroemulsion concentration is from 0.5 gpt (gallons per thousandgallons) to 4.0 gpt of the carrier fluid and a clay control additiveconcentration is from 0.25 gpt to 2.0 gpt of the carrier fluid. Onceinjected into the subterranean formation, the method may reduce theswelling of a swelling clay. In some embodiments, the well treatmentcomposition may provide an increase in the persistency of injectingcontinued clay swelling protection over a longer period of time duringand/or after flowback.

In another aspect, a method of treating a subterranean formation of anoil and/or gas well using a well treatment composition is provided. Themethod may comprise injecting a well treatment composition into asubterranean formation, the well treatment composition comprising amicroemulsion from 75 wt % to 90 wt % versus the total weight of thewell treatment composition, wherein the microemulsion comprises anaqueous phase from 10 wt % to 50 wt %, versus the total weight of themicroemulsion, a cationic surfactant from 10 wt % to 40 wt %, versus thetotal weight of the microemulsion, and a solvent from 5 wt % and 25 wt%, versus the total weight of the microemulsion, wherein the solvent isa terpene solvent. The well treatment composition may also comprise aclay control additive from 10 wt % to 25 wt % versus the total weight ofthe well treatment composition, wherein the clay control additivecomprises 30 wt % to 90 wt % water, versus the total weight of the claycontrol additive, and a clay control compound from 10 wt % to 70 wt %,versus the total weight of the clay control additive, wherein the claycontrol compound comprises a cationic polymer, and wherein the cationicpolymer comprises a polyquaternary amine. In some embodiments, the welltreatment composition further comprises a carrier fluid, wherein themicroemulsion concentration is from 0.5 gpt to 4.0 gpt of the carrierfluid and a clay control additive concentration is from 0.25 gpt to 2.0gpt of the carrier fluid. Once injected into the subterranean formation,the method may reduce the swelling of a swelling clay.

In yet another aspect, a method of treating a subterranean formation ofan oil and/or gas well using a well treatment composition is provided.The method may comprise injecting a well treatment composition into asubterranean formation, the well treatment composition comprising amicroemulsion from 75 wt % to 90 wt % versus the total weight of thewell treatment composition, wherein the microemulsion comprises anaqueous phase from 10 wt % to 50 wt %, versus the total weight of themicroemulsion, a non-ionic surfactant from 10 wt % to 40 wt %, versusthe total weight of the microemulsion, and a solvent from 5 wt % and 25wt %, versus the total weight of the microemulsion, wherein the solventis a terpene solvent. The well treatment composition may also comprise aclay control additive from 10 wt % to 25 wt % versus the total weight ofthe well treatment composition, wherein the clay control additivecomprises 30 wt % to 90 wt % water, versus the total weight of the claycontrol additive, and a clay control compound from 10 wt % to 70 wt %,versus the total weight of the clay control additive, wherein the claycontrol compound comprises a cationic polymer, and wherein the cationicpolymer comprises a polyquaternary amine. In some embodiments, the welltreatment composition further comprises a carrier fluid, wherein themicroemulsion concentration is from 0.5 gpt to 4.0 gpt of the carrierfluid and a clay control additive concentration is from 0.25 gpt to 2.0gpt of the carrier fluid. Once injected into the subterranean formation,the method may reduce the swelling of a swelling clay.

Other advantages and novel features of the present invention will becomeapparent from the following detailed description of various non-limitingembodiments of the invention when considered in conjunction with theaccompanying FIGURES. In cases where the present specification and adocument incorporated by reference include conflicting and/orinconsistent disclosure, the present specification shall control.

BRIEF DESCRIPTION OF THE DRAWINGS

Non-limiting embodiments of the present invention will be described byway of example with reference to the accompanying FIGURES, which areschematic and are not intended to be drawn to scale. In the FIGURES,each identical or nearly identical component illustrated is typicallyrepresented by a single numeral. For purposes of clarity, not everycomponent is labeled in every FIGURE, nor is every component of eachembodiment of the invention shown where illustration is not necessary toallow those of ordinary skill in the art to understand the invention. Inthe FIGURES:

FIG. 1 shows the capillary suction timer (CST) ratio measured for brine(the brine comprising 500 parts per million (ppm) TDS (CaCl₂) and NaCl₂in a 1:2 ratio by weight), 0.5 gpt of the clay control additives (CC1and CC3) and the well treatment composition comprising a microemulsionand clay control additives (0.5 gpt CC1 and 2 gpt ME3) and (0.5 gpt CC3and 2 gpt ME3), at 1 hour after adding the clay control additives andafter seven washes by the brine and FIG. 1 also shows the results ofpersistency tests, according to one set of embodiments.

DETAILED DESCRIPTION

This invention relates to well treatment compositions and methods ofusing the well treatment compositions, comprising certain microemulsionsin conjunction with certain clay control additives, to treat clayswelling in subterranean formations of oil and/or gas wells containingclay or clay minerals. In some embodiments, the well treatmentcomposition may be used to reduce swelling of a swelling clay, such assmectite or mixed layers of smectite and illite, that may be present inthe subterranean formation or rock formation. The choice of both theclay control additive and the microemulsion strongly depends on the typeand the amount of swelling clay present in the subterranean formation(sometimes referred to as the rock formation).

The unique combination of certain microemulsions and certain claycontrol additives produces a surprising, synergistic effect that has notbeen known in the industry. The synergistic effect of these twocomponents of the well treatment composition, provides at least twosynergistic benefits: (1) increase in clay control performance byproviding enhanced clay swelling protection (e.g., significantly reducesor prevents clay swelling of swelling clays), when compared to the useof the same clay control additive alone (i.e. use of the well treatmentcomposition without the microemulsion component); and (2) increase inthe persistency of clay swelling protection for a longer period of time(e.g. during flowback) as provided by the well treatment composition byreducing the susceptibility of the well treatment composition fromwashing away, when compared to using the same clay control additivealone (i.e. use of the well treatment composition without themicroemulsion component). As a result of the synergistic benefitsdescribed above, the concentration of clay control additive in theinventive well treatment composition can be reduced by up to four times,when compared to using the same clay control additive alone (i.e. use ofthe well treatment composition without the microemulsion)—while stillachieving the same, a similar, or a higher degree of clay controlperformance of reducing or preventing clay swelling of swelling clays(e.g. providing clay swelling protection) and while providing higherpersistency in clay control treatment (e.g. providing continued clayswelling protection over a longer period of time, such as duringflowback) as provided by the well treatment composition.

The use of up to four times less concentration of clay control additivein the well treatment composition, when compared to the use of the sameclay control additive alone (i.e. use of the well treatment compositionwithout the microemulsion) results in at least two advantages: (1) asubstantial decrease in the cost of clay control additives that wouldotherwise be necessary due to less concentration of clay control used;and (2) produces less damage to the subterranean formation as a resultof less concentration of clay control additive that would otherwise beneeded.

As discussed above, the well treatment composition, comprising certainmicroemulsions and certain clay control additives, shows an increase inpersistency of providing continued clay swelling protection (e.g.continued reduction of clay swelling of swelling clay) over a longerperiod of time as provided by the well treatment composition for claycontrol treatment, during and/or after flowback. After the welltreatment is completed and the well is placed into production and thewell treatment fluid is displaced, a persistent clay control treatmentwill continue to provide over a longer period of time, clay swellingprotection (e.g. substantially reduce or prevent clay swelling ofswelling clay), because of its permanent nature, which allows the welltreatment to remain on the surface of the rock formation in thesubterranean formation and continue to perform its function at reducingclay swelling of clay or clay minerals. The well treatment composition,comprising certain microemulsions and certain clay control additives, issignificantly superior when compared to using the same clay controladditive alone (i.e. using the well treatment composition without themicroemulsion).

The concentration of certain clay control additives used in conjunctionwith certain microemulsions can be substantially reduced compared to theconcentration used for the same clay control additive alone. Forexample, a service company tasked with performing clay control treatmentoperations may typically inject 2 gpt (i.e. 2 gallons of clay controladditive per thousand gallons of carrier fluid) to treat thesubterranean formation for clay swelling. However, by using theinventive well treatment composition (which comprises a certainmicroemulsion), it is possible for the service company to use as littleas 0.5 gpt of the same clay control additive within the welltreatment—which equates to a use concentration of four times less claycontrol additive. The use of substantially smaller concentration (up tofour times less) of clay control additive is highly desirable for costreduction purposes for an operator. In addition, by using substantiallysmaller concentration of clay control additives to treat clay swellingof swelling clays, the operator produces less damage to the subterraneanformation.

The combination of certain clay control additives and certainmicroemulsions significantly enhances clay swelling protection forswelling clays (i.e. substantially reduces or prevents clay swelling)for the formation, thereby reducing the undesirable effect of claysplugging pore throats and causing formation damage. In some embodiments,the efficiency of this combination significantly reduces the amount ofclay control concentration by up to four times, by up to three times, orby up to two times, when compared to use of the clay control additivealone (i.e. using the well treatment composition without themicroemulsion), while also achieving the same, a similar, or a higherdegree of performance of reducing clay swelling. The ability to usesignificantly less clay control additive in the well provides theadvantages of reduction of costs for the operator tremendously as wellas produces less damage to the subterranean formation.

Clay control protection (also known as clay control stabilization) canbe temporary or permanent depending on the clay control composition usedto treat the subterranean formation. A temporary clay control additivehas a temporary effect, whereby the clay control additive can be easilyremoved (e.g. washed away) during flowback. In contrast, a permanentclay control additive has higher persistency in the subterraneanformation, meaning that it provides higher persistent clay swellingprotection (e.g. continued clay swelling protection by reducing clayswelling for a longer period of time for swelling clays) on the rocksurfaces of the subterranean formation, because it is more resistance toremoval during flowback. Thus, another advantage of using this welltreatment composition of certain clay control additives and certainmicroemulsions is in the composition's ability to provide permanent(i.e. persistent) clay stabilization, even after being exposed andre-exposed to flowback, including water or diluted brines.

In some embodiments, the well treatment composition can be pumped (e.ginjected) in the field as part of a treatment fluid to enhance therecovery of hydrocarbon fluids produced from a hydrocarbon-bearingsubterranean formation.

The well treatment composition may further comprise a conventionalfracturing fluid, a remediation fluid, a drilling fluid, and anacidizing fluid. The amount of clay control additive in the welltreatment composition is typically between from about 0.25 gallons perthousand gallons of carrier fluid to about 5 gallons per thousandgallons of carrier fluid, depending of the application.

Microemulsion

The well treatment composition comprises a microemulsion. Themicroemulsion comprises an aqueous phase, a non-aqueous phase (e.g. asolvent), and a surfactant. In some embodiments, the microemulsion mayfurther comprise an alcohol and/or and a co-solvent. In someembodiments, the microemulsion further comprises additional additives.

In some embodiments, the microemulsion comprises from 60 wt % to 95 wt %versus the total weight of the well treatment composition, from 65 wt %to 90 wt % versus the total weight of the well treatment composition,from 70 wt % to 85 wt % versus the total weight of the well treatmentcomposition, from 70 wt % to 80 wt % versus the total weight of the welltreatment composition, from 75 wt % to 90 wt % versus the total weightof the well treatment composition, from 80 wt % to 90 wt % versus thetotal weight of the well treatment composition, or from 85 wt % to 95 wt% versus the total weight of the well treatment composition.

Details of each of the components of the microemulsion are described indetail below.

Aqueous Phase

The microemulsion may comprise an aqueous phase. The aqueous phasegenerally comprises water or is water. The water may be provided fromany suitable source (e.g., sea water, fresh water, deionized water,reverse osmosis water, water from field operations and production, wellwater, or plant water). The aqueous phase may also comprise dissolvedsalts. Non-limiting examples of dissolved salts include salts comprisingK, Na, Br, Cr, Cs, or Bi, for example, halides of these metals,including NaCl, KCl, CaCl₂), and MgCl and combinations thereof.

The aqueous phase may make up any suitable amount of the microemulsionby weight. The aqueous phase may make up greater than or equal to 1 wt%, greater than or equal to 2 wt %, greater than or equal to 5 wt %,greater than or equal to 10 wt %, greater than or equal to 15 wt %,greater than or equal to 20 wt %, greater than or equal to 25 wt %,greater than or equal to 30 wt %, greater than or equal to 35 wt %,greater than or equal to 40 wt %, greater than or equal to 45 wt %,greater than or equal to 50 wt %, greater than or equal to 55 wt %, orgreater than or equal to 60 wt % of the total weight of themicroemulsion composition. The aqueous phase may make up less than orequal to 60 wt %, less than or equal to 55 wt %, less than or equal to50 wt %, less than or equal to 45 wt %, less than or equal to 40 wt %,less than or equal to 35 wt %, less than or equal to 30 wt %, less thanor equal to 25 wt %, less than or equal to 20 wt %, less than or equalto 15 wt %, less than or equal to 10 wt %, less than or equal to 5 wt %,less than or equal to 2 wt %, or less than or equal to 1 wt % of thetotal weight of the microemulsion. Combinations of the above-referencedranges are also possible (e.g., greater than or equal to 1 wt % and lessthan or equal to 60 wt % of the total weight of the microemulsion,greater than or equal to 15 wt % and less than or equal to 30 wt % ofthe total weight of the microemulsion, greater than or equal to 20 wt %and less than or equal to 25 wt % of the total weight of themicroemulsion, greater than or equal to 10 wt % and less than or equalto 60 wt %, or greater than or equal to 10 wt % and less than 50 wt %).Other ranges are also possible.

Non-Aqueous Phase

The microemulsion may comprise a non-aqueous phase. The non-aqueousphase may comprise a solvent and/or a combination of solvents (e.g., inthe form of a solvent blend). The non-aqueous phase may make up anysuitable amount of the microemulsion by weight. The non-aqueous phasemay make up greater than or equal to 1 wt %, greater than or equal to 2wt %, greater than or equal to 3 wt %, greater than or equal to 4 wt %,greater than or equal to 5 wt %, greater than or equal to 10 wt %,greater than or equal to 15 wt %, greater than or equal to 20 wt %,greater than or equal to 25 wt %, or greater than or equal to 30 wt % ofthe total weight of the microemulsion. The non-aqueous phase may make upless than or equal to 30 wt % of the microemulsion, less than or equalto 25 wt % of the microemulsion, less than or equal to 20 wt % of themicroemulsion, less than or equal to 15 wt % of the microemulsion, lessthan or equal to 10 wt % of the microemulsion, less than or equal to 5wt % of the microemulsion, less than or equal to 4 wt %, less than orequal to 3 wt %, less than or equal to 2 wt %, or less than or equal to1 wt % of the total weight of the microemulsion. Combinations of theabove-referenced ranges are also possible (e.g., greater than or equalto 1 wt % and less than or equal to 30 wt % of the microemulsion,greater than or equal to 5 wt % and less than or equal to 25 wt %,greater than or equal to 15 wt % and less than or equal to 30 wt % ofthe microemulsion, or greater than or equal to 20 wt % and less than orequal to 25 wt % of the total weight of the microemulsion).

Terpene Solvents

In some embodiments, a non-aqueous phase of a microemulsion comprises aterpene solvent. In some embodiments, the non-aqueous phase comprises aterpene solvent and another different type of solvent (e.g., an alcoholand/or a glycol). In some embodiments, the non-aqueous phase comprises afirst terpene solvent and a second, different type of terpene solvent.

Terpene solvents are generally derived biosynthetically from units ofisoprene. Terpene solvents may be generally classified as monoterpenes(e.g. having two isoprene units), sesquiterpenes (e.g. having threeisoprene units), diterpenes, or the like. The term “terpenoid” includesnatural degradation products, such as ionones, and natural and syntheticderivatives, for example, terpene alcohols, ethers, aldehydes, ketones,acids, esters, epoxides, and hydrogenation products (see Ullmann'sEncyclopedia of Industrial Chemistry, 2012, pages 29-45, hereinincorporated by reference). In some embodiments, the terpene is anaturally occurring terpene. In some embodiments, the terpene is anon-naturally occurring terpene and/or a chemically modified terpene(e.g., saturated terpene, terpene amine, fluorinated terpene, orsilylated terpene). Terpenes that are modified chemically, such as byoxidation or rearrangement of the carbon skeleton, may be referred to asterpenoids. Many references use “terpene” and “terpenoid”interchangeably, and this disclosure will adhere to that usage.

In some embodiments, the terpene solvent is a non-oxygenated terpenesolvent. In some embodiments, the terpene solvent is a citrus terpene.In some embodiments, the terpene solvent is d-limonene. In someembodiments, the terpene solvent is dipentene. In some embodiments, theterpene solvent is selected from the group consisting of d-limonene,nopol, alpha terpineol, eucalyptol, dipentene, linalool, pinene,alpha-pinene, beta-pinene, alpha-terpinene, geraniol, alpha-terpinylacetate, menthol, menthone, cineole, citranellol, and combinationsthereof. As used herein, “terpene” refers to a single terpene compoundor a blend of terpene compounds.

In some embodiments, the terpene solvent is an oxygenated terpene.Non-limiting examples of oxygenated terpenes include terpenes containingalcohol, aldehyde, ether, or ketone groups. In some embodiments, theterpene comprises an ether-oxygen, for example, eucalyptol, or acarbonyl oxygen, for example, menthone. In some embodiments the terpenesolvent comprises a terpene alcohol. Non-limiting examples of terpenealcohols include linalool, geraniol, nopol, α-terpineol, and menthol.Non-limiting examples of oxygenated terpenes include eucalyptol,1,8-cineol, menthone, and carvone.

Alkyl Aliphatic Carboxylic Acid Ester Solvents

In some embodiments, a non-aqueous phase of a microemulsion comprises analkyl aliphatic carboxylic acid ester solvent. As used herein “alkylaliphatic carboxylic acid ester” refers to a compound or a blend ofcompounds having the general formula:

wherein R¹ is a C₄ to C₂₂ optionally substituted aliphatic group,including those bearing heteroatom-containing substituent groups, and R²is a C₁ to C₆ alkyl group. In some embodiments, R¹ is C₄ to C₂₂ alkyl.In some embodiments, R¹ is substituted with at least oneheteroatom-containing substituent group. For example, wherein a blend ofcompounds is provided and each R² is —CH₃ and each R¹ is independently aC₄ to C₂₂ aliphatic group, the blend of compounds is referred to asmethyl aliphatic carboxylic acid esters, or methyl esters. In someembodiments, such alkyl aliphatic carboxylic acid esters may be derivedfrom a fully synthetic process or from natural products, and thuscomprise a blend of more than one ester. In some embodiments, the alkylaliphatic carboxylic acid ester comprises butyl 3-hydroxybutyrate,isopropyl 3-hydroxybutyrate, hexyl 3-hydroxylbutyrate, and combinationsthereof.

Non-limiting examples of alkyl aliphatic carboxylic acid esters includemethyl octanoate, methyl decanoate, a blend of methyl octanoate andmethyl decanoate, and butyl 3-hydroxybutyrate.

Alkane Solvents

In some embodiments, a non-aqueous phase of a microemulsion comprises anunsubstituted cyclic or acyclic, branched or unbranched alkane solvent.In some embodiments, the cyclic or acyclic, branched or unbranchedalkane solvent has from 6 to 22 carbon atoms (e.g. from 6 to 10 carbonatoms). When the cyclic or acyclic alkane solvent is branched, thebranches may include 1 carbon atom (e.g., in the case of methylatedcyclic or acyclic alkane solvents), 2 carbon atoms (e.g., in the case ofethylated cyclic or acyclic alkane solvents), 3 carbon atoms (e.g., inthe case of propylated cyclic or acyclic alkane solvents), or morecarbon atoms. Non-limiting examples of unsubstituted, acyclic,unbranched alkanes include hexane, heptane, octane, nonane, decane,undecane, dodecane, and combinations thereof. Non-limiting examples ofunsubstituted, acyclic, branched alkanes include isomers ofmethylpentane (e.g., 2-methylpentane, 3-methylpentane), isomers ofdimethylbutane (e.g., 2,2-dimethylbutane, 2,3-dimethylbutane), isomersof methylhexane (e.g., 2-methylhexane, 3-methylhexane), isomers ofethylpentane (e.g., 3-ethylpentane), isomers of dimethylpentane (e.g.,2,2,-dimethylpentane, 2,3-dimethylpentane, 2,4-dimethylpentane,3,3-dimethylpentane), isomers of trimethylbutane (e.g.,2,2,3-trimethylbutane), isomers of methylheptane (e.g., 2-methylheptane,3-methylheptane, 4-methylheptane), isomers of dimethylhexane (e.g.,2,2-dimethylhexane, 2,3-dimethylhexane, 2,4-dimethylhexane,2,5-dimethylhexane, 3,3-dimethylhexane, 3,4-dimethylhexane), isomers ofethylhexane (e.g. 3-ethylhexane), isomers of trimethylpentane (e.g.,2,2,3-trimethylpentane, 2,2,4-trimethylpentane, 2,3,3-trimethylpentane,2,3,4-trimethylpentane), isomers of ethylmethylpentane (e.g.,3-ethyl-2-methylpentane, 3-ethyl-3-methylpentane), and combinationsthereof. Non-limiting examples of unsubstituted cyclic branched orunbranched alkanes include cyclohexane, methylcyclopentane,ethylcyclobutane, propylcyclopropane, isopropylcyclopropane,dimethylcyclobutane, cycloheptane, methylcyclohexane,dimethylcyclopentane, ethylcyclopentane, trimethylcyclobutane,cyclooctane, methylcycloheptane, dimethylcyclohexane, ethylcyclohexane,isopropylcyclohexane, cyclononane, methylcyclooctane,dimethylcycloheptane, ethylcycloheptane, trimethylcyclohexane,ethylmethylcyclohexane, propylcyclohexane, cyclodecane, and combinationsthereof. In some embodiments, the unsubstituted cyclic or acyclic,branched or unbranched alkane having from 6 to 12 carbon atoms isselected from the group consisting of heptane, octane, nonane, decane,2,2,4-trimethylpentane (isooctane), and propylcyclohexane, andcombinations thereof.

Unsaturated Hydrocarbon Solvents

In some embodiments, a non-aqueous phase of a microemulsion comprises asolvent that is an unsubstituted acyclic branched alkene orunsubstituted acyclic unbranched alkene having one or two double bondsand from 6 to 22 carbon atoms. In some embodiments, the non-aqueousphase comprises an unsubstituted acyclic branched alkene orunsubstituted acyclic unbranched alkene having one or two double bondsand from 6 to 22 carbon atoms. Non-limiting examples of unsubstitutedacyclic unbranched alkenes having one or two double bonds and from 6 to22 carbon atoms include isomers of hexene (e.g., 1-hexene, 2-hexene),isomers of hexadiene (e.g., 1,3-hexadiene, 1,4-hexadiene), isomers ofheptene (e.g., 1-heptene, 2-heptene, 3-heptene), isomers of heptadiene(e.g., 1,5-heptadiene, 1-6, heptadiene), isomers of octene (e.g.,1-octene, 2-octene, 3-octene), isomers of octadiene (e.g.,1,7-octadiene), isomers of nonene, isomers of nonadiene, isomers ofdecene, isomers of decadiene, isomers of undecene, isomers ofundecadiene, isomers of dodecene, isomers of dodecadiene, andcombinations thereof. In some embodiments, the acyclic, unbranchedalkene having one or two double bonds and from 6 to 12 carbon atoms isan alpha-olefin (e.g., 1-hexene, 1-heptene, 1-octene, 1-nonene,1-decene, 1-undecene, 1-dodecene). Non-limiting examples ofunsubstituted, acyclic, branched alkenes include isomers ofmethylpentene, isomers of dimethylpentene, isomers of ethylpentene,isomers of methylethylpentene, isomers of propylpentene, isomers ofmethylhexene, isomers of ethylhexene, isomers of dimethylhexene, isomersof methylethylhexene, isomers of methylheptene, isomers of ethylheptene,isomers of dimethylhexptene, isomers of methylethylheptene, andcombinations thereof. In a particular embodiment, the unsubstituted,acyclic, unbranched alkene having one or two double bonds and from 6 to12 carbon atoms is 1-octene, 1,7-octadiene, or a combination thereof.

Aromatic Solvents

In some embodiments, a non-aqueous phase of a microemulsion comprises anaromatic solvent having a boiling point from 300 to 400° F. Non-limitingexamples of aromatic solvents having a boiling point from 300 to 400° F.include butylbenzene, hexylbenzene, mesitylene, light aromatic naphtha,heavy aromatic naphtha, and combinations thereof.

In some embodiments, a non-aqueous phase of a microemulsion comprises anaromatic solvent having a boiling point from 175 to 300° F. Non-limitingexamples of aromatic liquid solvents having a boiling point from 175 to300° F. include benzene, xylenes, and toluene.

In a particular embodiment, the non-aqueous phase does not comprisetoluene or benzene.

Dialkyl Ether Solvents

In some embodiments, a non-aqueous phase of a microemulsion comprises asolvent that is a branched or unbranched dialkylether having the formulaC_(n)H_(2n+1)OC_(m)H_(2m+1) wherein n+m is from 6 to 22. In someembodiments, n+m is from 6 to 12, or from 6 to 10, or from 6 to 8.Non-limiting examples of branched or unbranched dialkylether compoundshaving the formula C_(n)H_(2n+1)OC_(m)H_(2m+1) include isomers ofC₃H₇OC₃H₇, isomers of C₄H₉OC₃H₇, isomers of C₅H₁₁OC₃H₇, isomers ofC₆H₁₃OC₃H₇, isomers of C₄H₉OC₄H₉, isomers of C₄H₉OC₅H₁₁, isomers ofC₄H₉OC₆H₁₃, isomers of C₅H₁₁OC₆H₁₃, and isomers of C₆H₁₃OC₆H₁₃. In aparticular embodiment, the branched or unbranched dialkylether is anisomer of C₆H₁₃OC₆H₁₃ (e.g. dihexylether).

Bicyclic Hydrocarbon Solvents

In some embodiments, a non-aqueous phase of a microemulsion comprises abicyclic hydrocarbon solvent with varying degrees of unsaturationincluding fused, bridgehead, and spirocyclic compounds. Non-limitingexamples of bicyclic solvents include isomers of decalin,tetrahydronaphthalene, norbornane, norbornene, bicyclo[4.2.0]octane,bicyclo[3.2.1]octane, spiro[5.5]dodecane, and combinations thereof.

Amine Solvents

In some embodiments, a non-aqueous phase of a microemulsion comprises asolvent that is an amine of the formula NR¹R²R³, wherein R¹, R², and R³are the same or different and are C₁₋₁₆ alkyl groups that are (i)branched or unbranched; (ii) cyclic or acyclic; and (iii) substituted orunsubstituted. In some embodiments any two of R¹, R², and R³ are joinedtogether to form a ring. In some embodiments, each of R¹, R², and R³ arethe same or different and are hydrogen or alkyl groups that are (i)branched or unbranched; (ii) cyclic or acyclic; and (iii) substituted orunsubstituted. In some embodiments, any two of R¹, R², and R³ are joinedtogether to form a ring, provided at least one of R¹, R², and R³ is amethyl or an ethyl group. In some embodiments, R¹ is C₁-C₆ alkyl groupthat is (i) branched or unbranched; (ii) cyclic or acyclic; and (iii)substituted or unsubstituted and R² and R³ are hydrogen or a C₈₋₁₆ alkylgroup that is (i) branched or unbranched; (ii) cyclic or acyclic; and(iii) substituted or unsubstituted. In some embodiments, R² and R³ maybe joined together to form a ring. In some embodiments, R¹ is a methylor an ethyl group and R² and R³ are the same or different and are C₈₋₁₆alkyl groups that are (i) branched or unbranched; (ii) cyclic oracyclic; and (iii) substituted or unsubstituted. In some embodiments R²and R³ may be joined together to form a ring. In some embodiments, R¹ isa methyl group and R² and R³ are the same or different and are hydrogenor C₈₋₁₆ alkyl groups that are (i) branched or unbranched; (ii) cyclicor acyclic; and (iii) substituted or unsubstituted. In some embodimentsR² and R³ may be joined together to form a ring. In some embodiments, R¹and R² are the same or different and are hydrogen or C₁-C₆ alkyl groupsthat are (i) branched or unbranched; (ii) cyclic or acyclic; and (iii)substituted or unsubstituted and R³ is a C₈₋₁₆ alkyl group that is (i)branched or unbranched; (ii) cyclic or acyclic; and (iii) substituted orunsubstituted. In some embodiments, R¹ and R² are the same or differentand are a methyl or an ethyl group and R³ is hydrogen or a C₁₋₆ alkylgroup that is (i) branched or unbranched; (ii) cyclic or acyclic; and(iii) substituted or unsubstituted. In some embodiments, R¹ and R² aremethyl groups and R³ is hydrogen or a C₈₋₁₆ alkyl group that is (i)branched or unbranched; (ii) cyclic or acyclic; and (iii) substituted orunsubstituted.

In some embodiments, the amine is of the formula NR¹R²R³, wherein R¹ ismethyl and R² and R³ are C₈₋₁₆ alkyl groups that are (i) branched orunbranched; (ii) cyclic or acyclic; and (iii) substituted orunsubstituted. In some embodiments R² and R³ are joined together to forma ring. Non-limiting examples of amines include isomers ofN-methyl-octylamine, isomers of N-methyl-nonylamine, isomers ofN-methyl-decylamine, isomers of N-methylundecylamine, isomers ofN-methyldodecylamine, isomers of N-methyl teradecylamine, isomers ofN-methyl-hexadecylamine, and combinations thereof. In some embodiments,the amine is N-methyl-decylamine, N-methyl-hexadecylamine, or acombination thereof.

In some embodiments, the amine is of the formula NR¹R²R³, wherein R¹ isa methyl group and R² and R³ are the same or different and are C₁₋₆alkyl groups that are (i) branched or unbranched; (ii) cyclic oracyclic; and (iii) substituted or unsubstituted.

In some embodiments R² and R³ are joined together to form a ring.Non-limiting examples of amines include isomers ofN-methyl-N-octyloctylamine, isomers of N-methyl-N-nonylnonylamine,isomers of N-methyl-N-decyldecylamine, isomers ofN-methyl-N-undecylundecylamine, isomers ofN-methyl-N-dodecyldodecylamine, isomers ofN-methyl-N-tetradecylteradecylamine, isomers ofN-methyl-N-hexadecylhexadecylamine, isomers ofN-methyl-N-octylnonylamine, isomers of N-methyl-N-octyldecylamine,isomers of N-methyl-N-octyldodecylamine, isomers ofN-methyl-N-octylundecylamine, isomers ofN-methyl-N-octyltetradecylamine, isomers ofN-methyl-N-octylhexadecylamine, N-methyl-N-nonyldecylamine, isomers ofN-methyl-N-nonyldodecylamine, isomers ofN-methyl-N-nonyltetradecylamine, isomers ofN-methyl-N-nonylhexadecylamine, isomers of N-methyl-N-decylundecylamine,isomers of N-methyl-N-decyldodecylamine, isomers ofN-methyl-N-decyltetradecylamine, isomers ofN-methyl-N-decylhexadecylamine, isomers ofN-methyl-N-dodecylundecylamine, isomers ofN-methyl-N-dodecyltetradecylamine, isomers ofN-methyl-N-dodecylhexadecylamine, isomers ofN-methyl-N-tetradecylhexadecylamine, and combinations thereof. In someembodiments, the amine is selected from the group consisting ofN-methyl-N-octyloctylamine, isomers of N-methyl-N-nonylnonylamine,isomers of N-methyl N-decyldecylamine, isomers ofN-methyl-N-undecylundecylamine, isomers ofN-methyl-N-dodecyldodecylamine, isomers ofN-methyl-N-tetradecylteradecylamine, and isomers ofN-methyl-N-hexadecylhexadecylamine, and combinations thereof. In someembodiments, the amine is N-methyl-N-dodecyldodecylamine, one or moreisomers of N-methyl-N-hexadecylhexadecylamine, or combinations thereof.In some embodiments, the amine is selected from the group consisting ofisomers of N-methyl-N-octylnonylamine, isomers ofN-methyl-N-octyldecylamine, isomers of N-methyl-N-octyldodecylamine,isomers of N-methyl-N-octylundecylamine, isomers ofN-methyl-N-octyltetradecylamine, isomers ofN-methyl-N-octylhexadecylamine, N-methyl-N-nonyldecylamine, isomers ofN-methyl-N-nonyldodecylamine, isomers ofN-methyl-N-nonyltetradecylamine, isomers ofN-methyl-N-nonylhexadecylamine, isomers of N-methyl-N-decyldodecylamine,isomers of N-methyl-N-decylundecylamine, isomers ofN-methyl-N-decyldodecylamine, isomers ofN-methyl-N-decyltetradecylamine, isomers ofN-methyl-N-decylhexadecylamine, isomers ofN-methyl-N-dodecylundecylamine, isomers ofN-methyl-N-dodecyltetradecylamine, isomers ofN-methyl-N-dodecylhexadecylamine, isomers ofN-methyl-N-tetradecylhexadecylamine, and combinations thereof. In someembodiments, the cyclic or acyclic, branched or unbranchedtri-substituted amine is selected from the group consisting ofN-methyl-N-octyldodecylamine, N-methyl-N-octylhexadecylamine, andN-methyl-N-dodecylhexadecylamine, and combinations thereof.

In some embodiments, the amine is of the formula NR¹R²R³, wherein R¹ andR² are methyl and R³ is a C₈₋₁₆ alkyl that is (i) branched orunbranched; (ii) cyclic or acyclic; and (iii) substituted orunsubstituted. Non-limiting examples of amines include isomers ofN,N-dimethylnonylamine, isomers of N,N-dimethyldecylamine, isomers ofN,N-dimethylundecylamine, isomers of N,N-dimethyldodecylamine, isomersof N,N-dimethyltetradecylamine, and isomers ofN,N-dimethylhexadecylamine. In some embodiments, the amine is selectedfrom the group consisting of N,N-dimethyldecylamine, isomers ofN,N-dodecylamine, and isomers of N,N-dimethylhexadecylamine.

Amide Solvents

In some embodiments, a non-aqueous phase of a microemulsion comprises anamide solvent. In some embodiments, the amide is of the formulaN(C═OR⁴)R⁵R⁶, wherein R⁴, R⁵, and R⁶ are the same or different and arehydrogen or C₄₋₁₆ alkyl groups wherein the alkyl groups are (i) branchedor unbranched; (ii) cyclic or acyclic; and (iii) substituted orunsubstituted. In some embodiments R⁵ and R⁶ are joined together to forma ring. In some embodiments, each of R⁴, R⁵, and R⁶ are the same ordifferent and are hydrogen or C₄₋₁₆ alkyl groups wherein the alkylgroups are (i) branched or unbranched; (ii) cyclic or acyclic; and (iii)substituted or unsubstituted, provided at least one of R⁴, R⁵, and R⁶ isa methyl or an ethyl group. In some embodiments R⁵ and R⁶ are joinedtogether to form a ring. In some embodiments, R⁴ is hydrogen, C₁-C₆alkyl, wherein the alkyl group is (i) branched or unbranched; (ii)cyclic or acyclic; and (iii) substituted or unsubstituted, and R⁵ and R⁶are the same or different and are hydrogen or C₈₋₁₆ alkyl groups whereinthe alkyl groups are (i) branched or unbranched; (ii) cyclic or acyclic;and (iii) substituted or unsubstituted. In some embodiments, R⁵ and R⁶are joined together to form a ring. In some embodiments, R⁴ is hydrogen,methyl, or ethyl and R⁵ and R⁶ are C₈₋₁₆ alkyl groups wherein the alkylgroups are (i) branched or unbranched; (ii) cyclic or acyclic; and (iii)substituted or unsubstituted. In some embodiments, R⁵ and R⁶ are joinedtogether to form a ring. In some embodiments, R⁴ is hydrogen and R⁵ andR⁶ are the same or different and are C₈₋₁₆ alkyl groups wherein thealkyl groups are (i) branched or unbranched; (ii) cyclic or acyclic; and(iii) substituted or unsubstituted. In some embodiments R⁵ and R⁶ arejoined together to form a ring. In some embodiments, R⁴ and R⁵ are thesame or different and are hydrogen or C₁-C₆ alkyl groups wherein thealkyl groups are (i) branched or unbranched; (ii) cyclic or acyclic; and(iii) substituted or unsubstituted and R⁶ is a C₈₋₁₆ alkyl group that is(i) branched or unbranched; (ii) cyclic or acyclic; and (iii)substituted or unsubstituted. In some embodiments, R⁴ and R⁵ are thesame or different and are independently hydrogen, methyl, or ethyl andR⁶ is a C₈₋₁₆ alkyl group that is (i) branched or unbranched; (ii)cyclic or acyclic; and (iii) substituted or unsubstituted. In someembodiments, R⁴ and R⁵ are hydrogen and R⁶ is a C₈₋₁₆ alkyl group thatis (i) branched or unbranched; (ii) cyclic or acyclic; and (iii)substituted or unsubstituted. In some embodiments, R⁶ is hydrogen or R⁶is a C₁₋₆ alkyl group that is (i) branched or unbranched; (ii) cyclic oracyclic; and (iii) substituted or unsubstituted and R⁴ and R⁵ are thesame or different and are C₈₋₁₆ alkyl groups wherein the alkyl groupsare (i) branched or unbranched; (ii) cyclic or acyclic; and (iii)substituted or unsubstituted. In some embodiments, R⁶ is hydrogen,methyl, or ethyl and R⁴ and R⁵ are the same or different and are C₈₋₁₆alkyl groups wherein the alkyl groups are (i) branched or unbranched;(ii) cyclic or acyclic; and (iii) substituted or unsubstituted. In someembodiments, R⁶ is hydrogen and R⁴ and R⁵ are the same or different andare C₈₋₆ alkyl groups wherein the alkyl groups are (i) branched orunbranched; (ii) cyclic or acyclic; and (iii) substituted orunsubstituted. In some embodiments, R⁵ and R⁶ are the same or differentand are hydrogen or C₁₋₆ alkyl groups wherein the alkyl groups are (i)branched or unbranched; (ii) cyclic or acyclic; and (iii) substituted orunsubstituted, and R⁴ is a C₈₋₁₆ alkyl group that is (i) branched orunbranched; (ii) cyclic or acyclic; and (iii) substituted orunsubstituted. In some embodiments, R⁵ and R⁶ are the same or differentand are independently hydrogen, methyl, or ethyl and R⁴ is a C₈₋₁₆ alkylgroup that is (i) branched or unbranched; (ii) cyclic or acyclic; and(iii) substituted or unsubstituted. In some embodiments, R⁵ and R⁶ arehydrogen and R⁴ is a C₈₋₁₆ alkyl group that is (i) branched orunbranched; (ii) cyclic or acyclic; and (iii) substituted orunsubstituted.

In some embodiments, the amide is of the formula N(C═OR⁴)R⁵R⁶, whereineach of R⁴, R⁵, and R⁶ are the same or different and are C₄₋₁₆ alkylgroups wherein the alkyl groups are (i) branched or unbranched; (ii)cyclic or acyclic; and (iii) substituted or unsubstituted. In someembodiments R⁵ and R⁶ are joined together to form a ring. In someembodiments, the amide is of the formula N(C═O R⁴)R⁵R⁶, wherein each ofR⁴, R⁵, and R⁶ are the same or different and are C₁₋₆ alkyl groupswherein the alkyl groups are (i) branched or unbranched; (ii) cyclic oracyclic; and (iii) substituted or unsubstituted.

In some embodiments R⁵ and R⁶ are joined together to form a ring.Non-limiting examples of amides include N,N-dioctyloctamide,N,N-dinonylnonamide, N,N-didecyldecamide, N,N-didodecyldodecamide,N,N-diundecylundecamide, N,N-ditetradecyltetradecamide,N,N-dihexadecylhexadecamide, N,N-didecyloctamide, N,N-didodecyloctamide,N,N-dioctyldodecamide, N,N-didecyldodecamide, N,N-dioctylhexadecamide,N,N-didecylhexadecamide, N,N-didodecylhexadecamide, and combinationsthereof. In some embodiments, the amide is N,N-dioctyldodecamide,N,N-didodecyloctamide, or a combination thereof.

In some embodiments, the amide is of the formula N(C═OR⁴)R⁵R⁶, whereinR⁶ is selected from the group consisting of hydrogen, methyl, ethyl,propyl and isopropyl, and R⁴ and R⁵ are the same or different and areC₄₋₁₆ alkyl groups wherein the alkyl groups are (i) branched orunbranched; (ii) cyclic or acyclic; and (iii) substituted orunsubstituted. In some embodiments, R⁶ is selected from the groupconsisting of hydrogen, methyl, ethyl, propyl and isopropyl, and R⁴ andR⁵ are the same or different and are C₄₋₈ alkyl groups wherein the alkylgroups are (i) branched or unbranched; (ii) cyclic or acyclic; and (iii)substituted or unsubstituted. In some embodiments, at least one of R⁴and R⁵ is substituted with a hydroxyl group. In some embodiments, atleast one of R⁴ and R⁵ is C₁₋₁₆ alkyl substituted with a hydroxyl group.

In some embodiments, the amide is of the formula N(C═OR⁴)R⁵R⁶, whereinR⁶ is C₁-C₃ alkyl and R⁴ and R⁵ are the same or different and are C₄₋₁₆alkyl groups that are (i) branched or unbranched; (ii) cyclic oracyclic; and (iii) substituted or unsubstituted. In some embodiments, R⁶is selected from the group consisting of methyl, ethyl, propyl, andisopropyl, and R⁴ and R⁵ are the same or different and are C₄₋₁₆ alkylgroups that are (i) branched or unbranched; (ii) cyclic or acyclic; and(iii) substituted or unsubstituted. In some embodiments, R⁶ is selectedfrom the group consisting of methyl, ethyl, propyl, and isopropyl, andR⁴ and R⁵ are the same or different and are C₈₋₁₆ alkyl groups that are(i) branched or unbranched; (ii) cyclic or acyclic; and (iii)substituted or unsubstituted. In some embodiments, at least one of R⁴and R⁵ is substituted with a hydroxyl group. In some embodiments, R⁶ isselected from the group consisting of methyl, ethyl, propyl, andisopropyl, and R⁴ and R⁵ are the same or different and are C₄₋₁₆ alkylgroups that are (i) branched or unbranched; (ii) cyclic or acyclic; and(iii) substituted or unsubstituted. In some embodiments at least one ofR⁴ and R⁵ is C₁₋₁₆ alkyl substituted with a hydroxyl group.

Non-limiting examples of amides include N,N-di-tert-butylformamide,N,N-dipentylformamide, N,N-dihexylformamide, N,N-diheptylformamide,N,N-dioctylformamide, N,N-dinonylformamide, N,N-didecylformamide,N,N-diundecylformamide, N,N-didodecylformamide,N,N-dihydroxymethylformamide, N,N-di-tert-butylacetamide,N,N-dipentylacetamide, N,N-dihexylacetamide, N,N-diheptylacetamide,N,N-dioctylacetamide, N,N-dinonylacetamide, N,N-didecylacetamide,N,N-diundecylacetamide, N,N-didodecylacetamide,N,N-dihydroxymethylacetamide, N,N-dimethylpropionamide,N,N-diethylpropionamide, N,N-dipropylpropionamide,N,N-di-n-propylpropionamide N,N-diisopropylpropionamide,N,N-dibutylpropionamide, N,N-di-n-butylpropionamide,N,N-di-sec-butylpropionamide, N,N-diisobutylpropionamide orN,N-di-tert-butylpropionamide, N,N-dipentylpropionamide,N,N-dihexylpropionamide, N,N-diheptylpropionamide,N,N-dioctylpropionamide, N,N-dinonylpropionamide,N,N-didecylpropionamide, N,N-diundecylpropionamide,N,N-didodecylpropionamide, N,N-dimethyl-n-butyramide,N,N-diethyl-n-butyramide, N,N-dipropyl-n-butyramide,N,N-di-n-propyl-n-butyramide or N,N-diisopropyl-n-butyramide,N,N-dibutyl-n-butyramide, N,N-di-n-butyl-n-butyramide,N,N-di-sec-butyl-n-butyramide, N,N-diisobutyl-n-butyramide,N,N-di-tert-butyl-n-butyramide, N,N-dipentyl-n-butyramide,N,N-dihexyl-n-butyramide, N,N-diheptyl-n-butyramide,N,N-dioctyl-n-butyramide, N,N-dinonyl-n-butyramide,N,N-didecyl-n-butyramide, N,N-diundecyl-n-butyramide,N,N-didodecyl-n-butyramide, N,N-dipentylisobutyramide,N,N-dihexylisobutyramide, N,N-diheptylisobutyramide,N,N-dioctylisobutyramide, N,N-dinonylisobutyramide,N,N-didecylisobutyramide, N,N-diundecylisobutyramide,N,N-didodecylisobutyramide, N,N-pentylhexylformamide,N,N-pentylhexylacetamide, N,N-pentylhexylpropionamide,N,N-pentylhexyl-n-butyramide, N,N-pentylhexylisobutyramide,N,N-methylethylpropionamide, N,N-methyl-n-propylpropionamide,N,N-methylisopropylpropionamide, N,N-methyl-n-butylpropionamide,N,N-methylethyl-n-butyramide, N,N-methyl-n-butyramide,N,N-methylisopropyl-n-butyramide, N,N-methyl-n-butyl-n-butyramide,N,N-methylethylisobutyramide, N,N-methyl-n-propylisobutyramide,N,N-methylisopropylisobutyramide, and N,N-methyl-n-butylisobutyramide.In some embodiments, the amide is selected from the group consisting ofN,N-dioctyldodecacetamide,N,N-methyl-N-octylhexadecyldidodecylacetamide,N-methyl-N-hexadecyldodecylhexadecacetamide, and combinations thereof.

In some embodiments, the amide is of the formula N(C═OR⁴)R⁵R⁶, whereinR⁶ is hydrogen or a methyl group and R⁴ and R⁵ are C₈₋₁₆ alkyl groupsthat are (i) branched or unbranched; (ii) cyclic or acyclic; and (iii)substituted or unsubstituted. Non-limiting amides include isomers ofN-methyloctamide, isomers of N-methylnonamide, isomers ofN-methyldecamide, isomers of N-methylundecamide, isomers of Nmethyldodecamide, isomers of N methylteradecamide, and isomers ofN-methyl-hexadecamide. In some embodiments, the amides are selected fromthe group consisting of N-methyloctamide, N-methyldodecamide,N-methylhexadecamide, and combinations thereof.

Non-limiting amides include isomers of N-methyl-N-octyloctamide, isomersof N-methyl-N-nonylnonamide, isomers of N-methyl-N-decyldecamide,isomers of N methyl-N undecylundecamide, isomers of Nmethyl-N-dodecyldodecamide, isomers of N methylN-tetradecylteradecamide, isomers of N-methyl-N-hexadecylhdexadecamide,isomers of N-methyl-N-octylnonamide, isomers ofN-methyl-N-octyldecamide, isomers of N-methyl-N-octyldodecamide, isomersof N-methyl-N-octylundecamide, isomers of N-methyl-N-octyltetradecamide,isomers of N-methyl-N-octylhexadecamide, N-methyl-N-nonyldecamide,isomers of N-methyl-N-nonyldodecamide, isomers ofN-methyl-N-nonyltetradecamide, isomers of N-methyl-N-nonylhexadecamide,isomers of N-methyl-N-decyldodecamide, isomers of Nmethyl-N-decylundecamide, isomers of N-methyl-N-decyldodecamide, isomersof N-methyl-N-decyltetradecamide, isomers ofN-methyl-N-decylhexadecamide, isomers of N methyl-N-dodecylundecamide,isomers of N methyl-N-dodecyltetradecamide, isomers ofN-methyl-N-dodecylhexadecamide, isomers of Nmethyl-N-tetradecylhexadecamide, and combinations thereof. In someembodiments, the amide is selected from the group consisting of isomersof N-methyl-N-octyloctamide, isomers of N-methyl-N-nonylnonamide,isomers of N-methyl-N-decyldecamide, isomers of N methyl-Nundecylundecamide, isomers of N methyl-N-dodecyldodecamide, isomers of Nmethyl N-tetradecylteradecamide, isomers ofN-methyl-N-hexadecylhdexadecamide, and combinations thereof. In someembodiments, amide is selected from the group consisting ofN-methyl-N-octyloctamide, N methyl-N-dodecyldodecamide, andN-methyl-N-hexadecylhexadecamide. In some embodiments, the amide isselected from the group consisting of isomers ofN-methyl-N-octylnonamide, isomers of N-methyl-N-octyldecamide, isomersof N-methyl-N-octyldodecamide, isomers of N-methyl-N-octylundecamide,isomers of N-methyl-N-octyltetradecamide, isomers ofN-methyl-N-octylhexadecamide, N-methyl-N-nonyldecamide, isomers ofN-methyl-N-nonyldodecamide, isomers of N-methyl-N-nonyltetradecamide,isomers of N-methyl-N-nonylhexadecamide, isomers ofN-methyl-N-decyldodecamide, isomers of N methyl-N-decylundecamide,isomers of N-methyl-N-decyldodecamide, isomers ofN-methyl-N-decyltetradecamide, isomers of N-methyl-N-decylhexadecamide,isomers of N methyl-N-dodecylundecamide, isomers of Nmethyl-N-dodecyltetradecamide, isomers ofN-methyl-N-dodecylhexadecamide, and isomers of Nmethyl-N-tetradecylhexadecamide. In some embodiments, the amide isselected from the group consisting of N-methyl-N-octyldodecamide,N-methyl-N-octylhexadecamide, and N-methyl-N-dodecylhexadecamide.

In some embodiments, the amide is of the formula N(C═OR⁴)R⁵R⁶, whereinR⁵ and R⁶ are the same or different and are hydrogen or C₁-C₃ alkylgroups and R⁴ is a C₄₋₁₆ alkyl group that is (i) branched or unbranched;(ii) cyclic or acyclic; and (iii) substituted or unsubstituted. In someembodiments, R⁵ and R⁶ are the same or different and are selected fromthe group consisting of hydrogen, methyl, ethyl, propyl and isopropyl,and R⁴ is a C₄₋₁₆ alkyl group that is (i) branched or unbranched; (ii)cyclic or acyclic; and (iii) substituted or unsubstituted. In someembodiments, R⁵ and R⁶ are the same or different and are selected fromthe group consisting of hydrogen, methyl, ethyl, propyl and isopropyland R⁴ is a C₈₋₁₆ alkyl group that is (i) branched or unbranched; (ii)cyclic or acyclic; and (iii) substituted or unsubstituted. In someembodiments, R⁴ is substituted with a hydroxyl group. In someembodiments, R⁵ and R⁶ are the same or different and are selected fromthe group consisting of hydrogen, methyl, ethyl, propyl, and isopropyl,and R⁴ is selected from the group consisting of tert-butyl and C₅₋₁₆alkyl groups that are (i) branched or unbranched; (ii) cyclic oracyclic; and (iii) substituted or unsubstituted, and C₁₋₁₆ alkyl groupsthat are (i) branched or unbranched; (ii) cyclic or acyclic; and (iii)substituted with a hydroxyl group.

In some embodiments, the amide is of the formula N(C═OR⁴)R⁵R⁶, whereinR⁵ and R⁶ are methyl groups and R⁴ is a C₈₋₁₆ alkyl group that is (i)branched or unbranched; (ii) cyclic or acyclic; and (iii) substituted orunsubstituted. Non-limiting examples of amides include isomers ofN,N-dimethyloctamide, isomers of N,N-dimethylnonamide, isomers ofN,N-dimethyldecamide, isomers of N,N-dimethylundecamide, isomers ofN,N-dimethyldodecamide, isomers of N,N-dimethyltetradecamide, isomers ofN,N-dimethylhexadecamide, and combinations thereof. In some embodiments,the cyclic or acyclic, branched or unbranched tri-substituted amines isselected from the group consisting of N,N-dimethyloctamide,N,N-dodecamide, and N,N-dimethylhexadecamide.

Alcohol Solvents

In some embodiments, a non-aqueous phase of a microemulsion comprises asolvent that is a cyclic or acyclic, branched or unbranched alkanehaving from 6 to 12 carbon atoms or from 5 to 10 carbon atoms, andsubstituted with a hydroxyl group. Non-limiting examples of cyclic oracyclic, branched or unbranched alkanes having from 6 to 12 carbon atomsor from 5 to 10 carbon atoms, and substituted with a hydroxyl groupinclude isomers of nonanol, isomers of decanol, isomers of undecanol,isomers of dodecanol, and combinations thereof. In a particularembodiment, the cyclic or acyclic, branched or unbranched alkane havingfrom 9 to 12 carbon atoms and substituted with a hydroxyl group is1-nonanol, 1-decanol, or a combination thereof.

In some embodiments, the alcohol solvent is selected from primary,secondary, and tertiary alcohols having from 9 to 12 carbon atoms.

Non-limiting examples of cyclic or acyclic, branched or unbranchedalkanes having from 5 to 10 carbon atoms, and substituted with ahydroxyl group include isomers of pentanol, isomers of hexanol, andisomers of heptanol.

Non-limiting examples of cyclic or acyclic, branched or unbranchedalkanes having 8 carbon atoms and substituted with a hydroxyl groupinclude isomers of octanol (e.g. 1-octanol, 2-octanol, 3-octanol,4-octanol), isomers of methyl heptanol, isomers of ethylhexanol (e.g.2-ethyl-1-hexanol, 3-ethyl-1-hexanol, 4-ethyl-1-hexanol), isomers ofdimethylhexanol, isomers of propylpentanol, isomers ofmethylethylpentanol, isomers of trimethylpentanol, and combinationsthereof. In a particular embodiment, the cyclic or acyclic, branched orunbranched alkane having 8 carbon atoms and substituted with a hydroxylgroup is 1-octanol, 2-ethyl-1-hexanol, or a combination thereof.

Surfactants

A wide variety of suitable surfactants may be employed in themicroemulsions described herein, examples of which are provided infurther detail below. The surfactant may make up any suitable amount ofthe microemulsion by weight. The surfactant may make up greater or equalto 10 wt %, greater than or equal to 20 wt %, greater than or equal to30 wt %, greater than or equal to 40 wt %, greater than or equal to 50wt %, greater than or equal to 60 wt % of the microemulsion, or greaterthan or equal to 65 wt % of the total weight of the microemulsion. Thesurfactant may make up less than or equal to 65 wt %, less than or equalto 60 wt %, less than or equal to 50 wt %, less than or equal to 40 wt%, less than or equal to 30 wt %, less than or equal to 20 wt %, lessthan or equal to 10 wt %, less than or equal to 5 wt %, less than orequal to 2 wt %, less than or equal to 1 wt %, less than or equal to 0.5wt %, less than or equal to 0.2 wt %, or less than or equal to 0.1 wt %,of the total weight of the microemulsion. Combinations of theabove-referenced ranges are also possible (e.g., greater than or equalto 0.1 wt % and less than or equal to 65 wt %, greater than or equal to10 wt % and less than or equal to 40 wt %, greater than or equal to 10wt % and less than or equal to 30 wt %, greater than or equal to 20 wt %and less than or equal to 30 wt %, or greater than or equal to 10 wt %and less than or equal to 50 wt %, of the total weight of themicroemulsion).

Non-limiting examples of suitable surfactants include nonionicsurfactants with linear or branched structure, including, but notlimited to, alkoxylated alcohols, alkoxylated fatty alcohols,alkoxylated castor oils, alkoxylated fatty acids, alkoxylated fattyamines, and alkoxylated fatty amides with a hydrocarbon chain of atleast 8 carbon atoms and 5 units or more of alkoxylation. The termalkoxylation includes ethoxylation and propoxylation. Other nonionicsurfactants include alkyl glycosides and alkyl glucamides.

It should be understood that a microemulsion may comprise onesurfactant, or may comprise two or more surfactants. In someembodiments, a microemulsion may comprise a co-surfactant in addition toone or more surfactants. The term surfactant is given its ordinarymeaning in the art and generally refers to compounds having anamphiphilic structure which gives them a specific affinity foroil/water-type and water/oil-type interfaces. In some embodiments, theaffinity helps the surfactants to reduce the free energy of theseinterfaces and to stabilize the dispersed phase of a microemulsion.

The term surfactant includes but is not limited to nonionic surfactants,anionic surfactants, cationic surfactants, amphoteric surfactants,zwitterionic surfactants, switchable surfactants, cleavable surfactants,dimeric or gemini surfactants, glucamide surfactants, alkylpolyglycoside surfactants, extended surfactants containing a nonionicspacer arm central extension and an ionic or nonionic polar group, andcombinations thereof. Nonionic surfactants generally do not contain anycharges. Anionic surfactants generally possess a net negative charge.Cationic surfactants generally possess a net positive charge. Amphotericsurfactants generally have both positive and negative charges, however,the net charge of the surfactant can be positive, negative, or neutral,depending on the pH of the solution. Zwitterionic surfactants aregenerally not pH dependent. A zwitterion is a neutral molecule with apositive and a negative electrical charge, though multiple positive andnegative charges can be present.

“Extended surfactants” are defined herein to be surfactants havingpropoxylated/ethoxylated spacer arms. The extended chain surfactants areintramolecular mixtures having at least one hydrophilic portion and atleast one lipophilic portion with an intermediate polarity portion inbetween the hydrophilic portion and the lipophilic portion; theintermediate polarity portion may be referred to as a spacer. Theyattain high solubilization in the single phase emulsion ormicroemulsion, and are in some instances, insensitive to temperature andare useful for a wide variety of oil types, such as natural or syntheticpolar oil types in a non-limiting embodiment. More information relatedto extended chain surfactants may be found in U.S. Pat. No. 8,235,120,which is incorporated herein by reference in its entirety.

The term co-surfactant as used herein is given its ordinary meaning inthe art and refers to compounds (e.g. pentanol) that act in conjunctionwith surfactants to form an emulsion or microemulsion.

In some embodiments, the one or more surfactants is a surfactantdescribed in U.S. patent application Ser. No. 14/212,731, filed Mar. 14,2014, entitled “METHODS AND COMPOSITIONS FOR USE IN OIL AND/OR GASWELLS,” now published as US/2014/0284053 on Sep. 25, 2014, hereinincorporated by reference. In some embodiments, the surfactant is asurfactant described in U.S. patent application Ser. No. 14/212,763,filed Mar. 14, 2014, entitled “METHODS AND COMPOSITIONS FOR USE IN OILAND/OR GAS WELLS,” now published as US/2014/0338911 on Nov. 20, 2014 andissued as U.S. Pat. No. 9,884,988 on Feb. 6, 2018, herein incorporatedby reference.

In some embodiments, the surfactants described herein in conjunctionwith solvents, generally form microemulsions that may be diluted to ause concentration to form an oil-in-water nanodroplet dispersion and/ora diluted microemulsion.

In some embodiments, the surfactants generally have hydrophile-lipophilebalance (HLB) values from 8 to 18 or from 8 to 14.

Non-limiting examples of different surfactants that may be present inthe microemulsion are provided below.

Hydrocarbon Surfactants

In some embodiments, a microemulsion comprises a hydrophilic hydrocarbonsurfactant. The hydrophilic hydrocarbon surfactant may comprise analcohol ethoxylate, wherein the alcohol ethoxylate contains ahydrocarbon group of 10 to 18 carbon atoms or from 12 to 15 carbonatoms, and contains an ethoxylate group of 5 to 12 ethylene oxide units(e.g., 7 ethylene oxide units, 10 ethylene oxide units). Non-limitingexamples of suitable alcohol ethoxylates include C₁₂-C₁₅ E₇, C₁₂-C₁₅ E₉,C₁₂-C₁₅ E₁₂, C₁₂-C₁₈ E₁₀, and C₁₂ E₇.

Nonionic Surfactants

In some embodiments, a microemulsion comprises a nonionic surfactant. Insome embodiments, the surfactant is an alkoxylated aliphatic alcoholhaving from 3 to 40 ethylene oxide (EO) units and from 0 to 20 propyleneoxide (PO) units. The term aliphatic alcohol generally refers to abranched or linear, saturated or unsaturated aliphatic moiety havingfrom 6 to 18 carbon atoms.

In some embodiments, a microemulsion comprises a surfactant is selectedfrom the group consisting of ethoxylated fatty acids, ethoxylated fattyamines, and ethoxylated fatty amides wherein the fatty portion is abranched or linear, saturated or unsaturated aliphatic hydrocarbonmoiety having from 6 to 18 carbon atoms.

In some embodiments, a microemulsion comprises a surfactant that is analkoxylated castor oil. In some embodiments, the surfactant is asorbitan ester derivative. In some embodiments the surfactant is anethylene oxide-propylene oxide copolymer wherein the total number ofethylene oxide (EO) and propylene oxide (PO) units is from 8 to 40units. In some embodiments, the surfactant is an alkoxylated tristyrylphenol containing from 6 to 100 total ethylene oxide (EO) and propyleneoxide (PO) units (e.g. tristyrylphenol E₁₆).

Nonionic Tristyryl Phenol Surfactants

In some embodiments, the surfactant has a structure as in Formula I:

wherein each of R⁷, R⁸, R⁹, R¹⁰, and R¹¹ are the same or different andare selected from the group consisting of hydrogen, optionallysubstituted alkyl, and —CH═CHAr, wherein Ar is an aryl group, providedat least one of R⁷, R⁸, R⁹, R¹⁰, and R¹¹ is —CH═CHAr, R¹² is hydrogen oralkyl, n is 1-100, and each m is independently 1 or 2. In someembodiments, Ar is phenyl. In some embodiments, for a compound ofFormula (I), R¹² is hydrogen or C₁₋₆ alkyl. In some embodiments, for acompound of Formula (I), R¹² is H, methyl, or ethyl. In someembodiments, for a compound of Formula (I), R¹² is H.

In some embodiments the surfactant of Formula I is a nonionic tristyrylphenol ethoxylate surfactant. In some embodiments, the nonionictristyryl phenol surfactant comprises a tristyryl phenol ethoxylatecontaining 10 to 30 ethylene oxide (EO) units. In some embodiments, thenonionic tristyryl phenol surfactant comprises a tristyryl phenolethoxylate containing 16 ethylene oxide (EO) units.

Amine and Amide Surfactants

In some embodiments, a microemulsion comprises an amine or an amide.Suitable amines include lauryl diethanolamine and laurylaminopropylamine. Suitable amides include lauryl diethanolamide andlauryl amidopropylamine. In some embodiments, a microemulsion comprisesan amine-based surfactant selected from the group consisting ofethoxylated alkylene amines, ethoxylated alkyl amines, propoxylatedalkylene amines, propoxylated alkyl amines, ethoxylated-propoxylatedalkylene amines and ethoxylated propoxylated alkyl amines. Theethoxylated/propoxylated alkylene or alkyl amine surfactant componentpreferably includes more than one nitrogen atom per molecule. Suitableamines include ethylenediaminealkoxylate anddiethylenetriaminealkoxylate.

Polyimine Surfactants

In some embodiments, a microemulsion comprises a surfactant that is analkoxylated polyimine with a relative solubility number (RSN) in therange of 5-20. As will be known to those of ordinary skill in the art,RSN values are generally determined by titrating water into a solutionof surfactant in 1,4 dioxane. The RSN values are generally defined asthe amount of distilled water necessary to be added to producepersistent turbidity. In some embodiments the surfactant is analkoxylated novolac resin (also known as a phenolic resin) with arelative solubility number in the range of 5-20.

In some embodiments the surfactant is a block copolymer surfactant witha total molecular weight greater than 5,000 g/mol. The block copolymermay have a hydrophobic block that is comprised of a polymer chain thatis linear, branched, hyperbranched, dendritic or cyclic.

Glycoside and Glycamide Surfactants

In some embodiments, the microemulsion comprises a surfactant that is analiphatic polyglycoside having the following formula:

wherein R³ is an aliphatic group having from 6 to 18 carbon atoms; eachR⁴ is independently selected from H, —CH₃, or —CH₂CH₃; Y is an averagenumber of from 0 to 5; and X is an average degree of polymerization (DP)of from 1 to 4; G is the residue of a reducing saccharide, for example,a glucose residue. In some embodiments, Y is zero.

In some embodiments, a microemulsion comprises a surfactant that is analiphatic glycamide having the following formula:

wherein R⁶ is an aliphatic group having from 6 to 18 carbon atoms; R⁵ isan alkyl group having from 1 to 6 carbon atoms; and Z is—CH₂(CH₂OH)_(b)CH₂OH, wherein b is from 3 to 5. In some embodiments, R⁵is —CH₃. In some embodiments, R⁶ is an alkyl group having from 6 to 18carbon atoms. In some embodiments, b is 3. In some embodiments, b is 4.In some embodiments, b is 5.

Anionic Surfactants

Suitable anionic surfactants of the microemulsion include, but are notnecessarily limited to, alkali metal alkyl sulfates, alkyl or alkylarylsulfonates, linear or branched alkyl ether sulfates and sulfonates,alcohol polypropoxylated and/or polyethoxylated sulfates, alkyl oralkylaryl disulfonates, alkyl disulfates, alkyl sulphosuccinates, alkylether sulfates, linear and branched ether sulfates, fatty carboxylates,alkyl sarcosinates, alkyl phosphates and combinations thereof.

In some embodiments, a microemulsion and comprises a surfactant that isan aliphatic sulfate wherein the aliphatic moiety is a branched orlinear, saturated or unsaturated aliphatic hydrocarbon moiety havingfrom 6 to 18 carbon atoms. In some embodiments, the surfactant is analiphatic sulfonate wherein the aliphatic moiety is a branched orlinear, saturated or unsaturated aliphatic hydrocarbon moiety havingfrom 6 to 18 carbon atoms.

In some embodiments, a microemulsion comprises a surfactant that is analiphatic alkoxy sulfate wherein the aliphatic moiety is a branched orlinear, saturated or unsaturated aliphatic hydrocarbon moiety havingfrom 6 to 18 carbon atoms and from 4 to 40 total ethylene oxide (EO) andpropylene oxide (PO) units.

In some embodiments, a microemulsion comprises a surfactant that is analiphatic-aromatic sulfate wherein the aliphatic moiety is a branched orlinear, saturated or unsaturated aliphatic hydrocarbon moiety havingfrom 6 to 18 carbon atoms. In some embodiments, the surfactant is analiphatic-aromatic sulfonate wherein the aliphatic moiety is a branchedor linear, saturated or unsaturated aliphatic hydrocarbon moiety havingfrom 6 to 18 carbon atoms.

In some embodiments, a microemulsion comprises a surfactant that is anester or half ester of sulfosuccinic acid with monohydric alcohols.

Anionic Tristyryl Phenol Surfactants

In some embodiments, the surfactant has a structure as in Formula II:

wherein each of R⁷, R⁸, R⁹, R¹⁰, and R¹¹ are the same or different andare selected from the group consisting of hydrogen, optionallysubstituted alkyl, and —CH═CHAr, wherein Ar is an aryl group, providedat least one of R⁷, R⁸, R⁹, R¹⁰, and R¹¹ is —CH═CHAr, Y⁻ is an anionicgroup, X⁺ is a cationic group, n is 1-100, and each m is independently 1or 2. In some embodiments, Ar is phenyl. In some embodiments, for acompound of Formula (II), X⁺ is a metal cation or N(R¹³)₄, wherein eachR¹³ is independently selected from the group consisting of hydrogen,optionally substituted alkyl, or optionally substituted aryl. In someembodiments, X⁺ is NH₄. Non-limiting examples of metal cations are Na⁺,K⁺, Mg⁺², and Ca⁺². In some embodiments, for a compound of Formula (II),Y⁻ is —O—, —SO₂O⁻, or —OSO₂O⁻.

Cationic Surfactants

In some embodiments, a microemulsion comprises a cationic surfactant. Insome embodiments, the surfactant comprises cationic quaternary ammoniumand ethoxylated alcohol. In some embodiments, the surfactant comprisescationic surfactant that is a quaternary alkylammonium salt or aquaternary alkylbenzylammonium salt, cocohydroxyethyl benzyl quaternary,whose alkyl groups have 1 to 24 carbon atoms (e.g., a halide, sulfate,phosphate, acetate, or hydroxide salt). In some embodiments, thesurfactant is a quaternary alkylbenzylammonium salt, whose alkyl groupshave 1-24 carbon atoms (e.g., a halide, sulfate, phosphate, acetate, orhydroxide salt). In some embodiments, the surfactant is analkylpyridinium, an alkylimidazolinium, or an alkyloxazolinium saltwhose alkyl chain has up to 18 carbons atoms (e.g., a halide, sulfate,phosphate, acetate, or hydroxide salt).

In some embodiments, the cationic surfactant comprises a benzyl cocoalkylbis (hydroxyethyl) chloride ethoxylated alcohol.

In some embodiments, a microemulsion comprises a surfactant that is acationic surfactant such as, monoalkyl quaternary amines, such ascocotrimethylammonium chloride, cetyltrimethylammonium chloride,stearyltrimethylammonium chloride, soyatrimethylammonium chloride,behentrimethylammonium chloride, and the like and mixtures thereof.Other suitable cationic surfactants that may be useful include, but arenot necessarily limited to, dialkylquaternary amines such asdicetyldimethylammonium chloride, dicocodimethylammonium chloride,distearyldimethylammonium chloride, and the like and mixtures thereof.

Cationic Tristyryl Phenol Surfactants

In some embodiments, the surfactant has a structure as in Formula III:

wherein each of R⁷, R⁸, R⁹, R¹⁰, and R¹¹ are the same or different andare selected from the group consisting of hydrogen, optionallysubstituted alkyl, and —CH═CHAr, wherein Ar is an aryl group, providedat least one of R⁷, R⁸, R⁹, R¹⁰, and R¹¹ is —CH═CHAr, Z⁺ is a cationicgroup, n is 1-100, and each m is independently 1 or 2. In someembodiments, Ar is phenyl. In some embodiments, for a compound ofFormula (III), Z⁺ is N(R¹³)₃, wherein each R¹³ is independent selectedfrom the group consisting of hydrogen, optionally substituted alkyl, oroptionally substituted aryl.

In some embodiments, for a compound of Formula (I), (II), or (III), twoof R⁷, R⁸, R⁹, R¹⁰, and R¹¹ are —CH═CHAr. In some embodiments, for acompound of Formula (I), (II), or (III), one of R⁷, R⁸, R⁹, R¹⁰, and R¹¹is —CH═CHAr and each of the other groups is hydrogen. In someembodiments, for a compound of Formula (I), (II), or (III), two of R⁷,R⁸, R⁹, R¹⁰, and R¹¹ are —CH═CHAr and each of the other groups ishydrogen. In some embodiments, for a compound of Formula (I), (II), or(III), R⁷ and R⁸ are —CH═CHAr and R⁹, R¹⁰, and R¹¹ are each hydrogen. Insome embodiments, for a compound of Formula (I), (II), or (III), threeof R⁷, R⁸, R⁹, R¹⁰, and R¹¹ are —CH═CHAr and each of the other groups ishydrogen. In some embodiments, for a compound of Formula (I), (II), or(III), R⁷, R⁸, and R⁹ are —CH═CHAr and R¹⁰ and R¹¹ are each hydrogen. Inembodiments, for a compound of Formula (I), (II), or (III), Ar isphenyl. In some embodiments, for a compound of Formula (I), (II), or(III), each m is 1. In some embodiments, for a compound of Formula (I),(II), or (III), each m is 2. In some embodiments, for a compound ofFormula (I), (II), or (III), n is 6-100, or 1-50, or 6-50, or 6-25, or1-25, or 5-50, or 5-25, or 5-20.

Zwitterionic and Amphoteric Surfactants

In some embodiments, a microemulsion comprises a zwitterionic oramphoteric surfactant. In some embodiments, a microemulsion comprises asurfactant that is an amine oxide (e.g. dodecyldimethylamine oxide). Insome embodiments, the surfactant is amphoteric or zwitterionic,including sultaines (e.g. cocamidopropyl hydroxysultaine), betaines(e.g. cocamidopropyl betaine), or phosphates (e.g. lecithin).

Alcohols

In some embodiments, a microemulsion further comprises an alcohol. Thealcohol may also be a freezing point depression agent for themicroemulsion. That is, the alcohol may lower the freezing point of themicroemulsion.

In some embodiments, a microemulsion comprises from 1 wt % to 50 wt %,from 1 wt % to 40 wt %, from 1 wt % to 35 wt %, or from 1 wt % to 30 wt% alcohol of the total weight of the microemulsion composition. In someembodiments, a microemulsion comprises from 5 wt % to 40 wt %, from 5 wt% to 35 wt % or from 10 wt % to 30 wt % alcohol of the total weight ofthe microemulsion composition.

In some embodiments, the alcohol is selected from primary, secondary,and tertiary alcohols having from 1 to 4 carbon atoms. In someembodiments, the alcohol comprises methanol, ethanol, isopropanol,n-propanol, n-butanol, i-butanol, sec-butanol, iso-butanol, t-butanol,or combinations thereof.

Co-Solvent

In some embodiments, the microemulsion further comprises a co-solvent.The co-solvent may serve as a coupling agent between the solvent and thesurfactant and/or may aid in the stabilization of the microemulsion.

In some embodiments, a microemulsion comprises from 1 wt % to 50 wt %,from 1 wt % to 40 wt %, from 1 wt % to 35 wt %, or from 1 wt % to 30 wt% co-solvent of the total weight of the microemulsion composition. Insome embodiments, a microemulsion comprises from 5 wt % to 40 wt %, from5 wt % to 35 wt % or from 10 wt % to 30 wt % co-solvent of the totalweight of the microemulsion composition.

In some embodiments, the co-solvent comprises ethylene glycol, propyleneglycol, dipropylene glycol monomethyl ether, triethylene glycol,ethylene glycol monobutyl ether, or combinations thereof.

Clay Control Additive

The well treatment composition comprises a clay control additive. Theclay control additive comprises water and a clay control compound. Insome embodiments, the clay control additive comprises from 5 wt % to 30wt %, from 10 wt % to 25 wt %, from 15 wt % to 20 wt %, from 20 wt % to25 wt %, or from 20 wt % to 30 wt %, versus the total weight of the welltreatment composition.

Water

In some embodiments, the water is from about 30 wt % to about 90 wt %,about 35 wt % to about 85 wt %, about 40 wt % to about 80 wt %, about 45wt % to about 75 wt %, about 50 wt % to about 70 wt %, about 55 wt % toabout 65 wt %, or about 60 wt %, of the total weight of the clay controladditive.

Clay Control Compound

In some embodiments, the clay control compound comprises a cationicpolymer, a small molecule quaternary amine, a salt, or combinationsthereof. In some embodiments, the clay control additive comprises amixture (also known as a blend) of two or more types of clay controlcompounds.

Examples of cationic polymers comprise polyquaternary amines having amolecular weight of less than 5,000 atomic mass units (amu) andpolyquaternary ammonium resins having a molecular weight of less than5,000 amu. Examples of cationic polyquaternary amines comprisepolydimethyldiallyl ammonium chloride and polyquaternary ammoniumresins. Examples of small molecule quaternary amines comprise cholinechloride and tetramethylammonium chloride. Examples of the saltscomprise sodium chloride (NaCl), potassium chloride (KCl), calciumchloride (CaCl₂), magnesium chloride (MgCl₂), ammonium chloride (NH₄Cl),or combinations thereof.

In some embodiments, the salt comprises about 1 wt % to about 10 wt %,about 2 wt % to about 9 wt %, about 3 wt % to about 8 wt %, about 4 wt %to about 7 wt %, or about 5 wt % to about 6 wt %, of the total weight ofthe clay control additive.

In some embodiment, the clay control additive may further comprise aglycol. Examples of glycols comprise ethylene glycol, propylene glycol,dipropylene glycol monomethyl ether, triethylene glycol, ethylene glycolmonobutyl ether, or combinations thereof.

In some embodiments, the clay control compound comprises from about 10wt % to about 70 wt % of the total weight of the clay control additive.In some embodiments, the clay control compound comprises from about 15wt % to about 65 wt %, about 20 wt % to about 60 wt %, about 25 wt % toabout 55 wt %, about 30 wt % to about 50 wt %, about 30 wt % to about 40wt %, about 35 wt % to about 45 wt %, or about 40 wt % of the totalweight of the clay control additive.

In some embodiments, the well treatment composition comprises themicroemulsion from about 75 wt % to about 90 wt % versus the totalweight of the well treatment composition. In some embodiments, the welltreatment composition comprises the clay control additive from about 10wt % to about 25 wt % versus the total weight of the well treatmentcomposition.

Methods of Using Well Treatment Composition

The well treatment composition described herein may be used in variousmethods of treating an oil and/or gas well for clay control protection,during the life cycle of the well, including, but not limited todrilling, hydraulic fracturing, stimulation, enhanced oil recovery (EOR)operations, improved oil recovery (IOR) operations, acidizing, wellboreclean outs, and water flooding applications.

The synergistic effects of (1) enhanced clay swelling protection; and(2) enhanced persistency—in using a combination of a certainmicroemulsion and a certain clay control additive to form a welltreatment composition, has not been known in the industry. The welltreatment composition can reduce up to four times less, up to threetimes less, or up to two times less concentration of clay controladditive needed when compared to the same clay control additive usedalone (i.e. well treatment composition without the microemulsion), toachieve the same, a similar, or a higher degree of performance ofreducing clay swelling and while also providing for a more persistentclay control treatment. The advantage of having to use lessconcentration of clay control additives in the well helps substantiallyreduce the operator's costs in purchasing less clay control additivesand also produces less damage to the subterranean formation.

First, a microemulsion composition is provided, comprising an aqueousphase, a surfactant, and a solvent. Next, a clay control additive isprovided, comprising water and a clay control compound. Themicroemulsion and clay control additive are added, mixed, or combined onthe fly with a carrier fluid to form a well treatment composition. Insome embodiments, additional additives may be mixed or combined on thefly with the well treatment composition.

In certain cases, the microemulsion and/or the clay control additivecomponents may be added with a carrier fluid, to form the well treatmentcomposition, and then injected or delivered to the subterraneanformation of an oil/and or gas well. A carrier fluid may act to deliverone of either the microemulsion or the clay control additive components(or both) to a well site in order to minimize clay swelling at or nearthe fracturing site. In certain cases, the carrier fluid is anaqueous-based fluid. Non-limiting examples of suitable carrier fluidsinclude water, fresh water, formation water, produced water andfracturing water. In some cases, the carrier fluid may be a brine, whichis water comprising various salts at various salinities.

The microemulsion and clay control additive components of the welltreatment composition may be formed at a variety of suitableconcentrations. In some embodiments, the microemulsion may be used ordosed at a microemulsion concentration from 0.5 gpt to 4.0 gpt ofcarrier fluid (gallons of microemulsion per thousand gallons of carrierfluid), from 1.0 gpt to 3.5 gpt of carrier fluid, from 1.5 gpt to 3.0gpt of carrier fluid, or from 2.0 gpt to 2.5 gpt of carrier fluid. Incertain embodiments, the microemulsion may be used or dosed at amicroemulsion concentration of 0.5 gpt of carrier fluid, 0.75 gpt ofcarrier fluid 1.0 gpt of carrier, 1.25 gpt of carrier fluid, 1.5 gpt ofcarrier fluid, 1.75 gpt of carrier fluid, 2.0 gpt of carrier fluid, 2.25gpt of carrier fluid, 2.5 gpt of carrier fluid, 2.75 gpt of carrierfluid, 3.0 gpt of carrier fluid, 3.25 gpt of carrier fluid, 3.5 gpt ofcarrier fluid, 3.75 gpt of carrier fluid, or 4.0 gpt of carrier fluid.

In some embodiments, the clay control additive may be used or dosed at aclay control additive concentration from 0.25 gpt to 2.0 gpt of carrierfluid (gallons of clay control additive per thousand gallons of carrierfluid), from 0.5 gpt to 1.75 gpt of carrier fluid, from 0.75 gpt to 1.5gpt of carrier fluid, or from 1.0 gpt to 1.25 gpt of carrier fluid. Incertain embodiments, the clay control additive may be used or dosed at aclay control additive concentration of 0.25 gpt of carrier fluid, 0.5gpt of carrier fluid, 0.75 gpt of carrier fluid, 1.0 gpt of carrierfluid, 1.25 gpt of carrier fluid, 1.5 gpt of carrier fluid, 1.75 gpt ofcarrier fluid, or 2.0 gpt of carrier fluid.

The choice of suitable concentrations or doses is not limited by thedelivery capabilities of any given pump or any delivery method.

The well treatment composition is injected (i.e. pumped) at highpressure downhole into the oil and/or gas well using pumping equipment.The well treatment composition comes into contact with the subterraneanformation of the reservoir, where clay or clay minerals may be present.The well treatment composition binds to the clay or clay mineralsurfaces to enhance clay swelling protection (i.e. substantially reduceor prevent clay swelling), while also enhancing persistency in providingcontinued clay control protection at enhancing clay swelling protection.

In some embodiments, the clay control additive concentration of the welltreatment composition is up to four times less when compared to aconcentration of the clay control additive alone when injected into thesubterranean formation to achieve the same, a similar, or a higherdegree of the reducing swelling of the swelling clay. As describedherein, one significant advantage of using the well treatmentcomposition is the cost savings. During the life cycle of oil and/or gaswells, well treatment operations are incredibly expensive, whereintreating one well can cost an operator millions of dollars. The highexpense is due, in part, to the cost of various chemical additives usedto treat the wells, including microemulsions and clay control additives.However, with the well treatment composition described herein, anoperator is able to save cost, because the clay control additivecomponent of the well treatment composition, can be used up to fourtimes less, up to three times less, or up to two times lessconcentration of the same clay control additive, while achieving thesame, a similar, or a higher degree of performance when compared tousing the clay control additive alone (i.e. use of the well treatmentcomposition without the microemulsion) and also having more persistencyin provided continued clay swelling protection. The ability for anoperator to spend up to four times less, up to three times less, up totwo times less money on clay control additives, results in significantcost savings. In addition, the well treatment composition produces lessdamage to the subterranean formation, because less clay controladditives are used to treat the well.

Furthermore, not only does the operator save up to four times, up tothree times, or up to two times in cost on clay control additiveexpenditures, the operator may also enjoy the benefits of the same, asimilar, or a higher degree of performance in reducing or preventingclay swelling (e.g. of swelling clays) and greater persistency inreducing or preventing clay swelling (e.g. of swelling clays). By havinggreater persistency, the well treatment composition remains persistentat continuing to reduce or prevent clay swelling because it is resistantto being washed off of the surfaces of the subterranean formation (e.gduring flowback).

Any suitable method for injecting or pumping the well treatmentcomposition into a wellbore may be employed. For example, in someembodiments, the well treatment composition may be injected into asubterranean formation (e.g. a reservoir) by injecting it into a well orwellbore in the zone of interest of the subterranean formation andthereafter pressurizing it into the formation for a selected distance.Methods for achieving the placement of a selected quantity of a mixturein a subterranean formation are known in the art. The well may betreated with the well treatment composition for a suitable period oftime. The well treatment composition and/or other fluids may later beremoved from the well using known techniques, including producing thewell.

It should be understood, that in embodiments where the well treatmentcomposition is said to be injected into a wellbore, the well treatmentcomposition may be diluted and/or combined with other liquidcomponent(s) prior to and/or during injection (e.g., via straight tubingor via coiled tubing, etc.) to form a well treatment fluid. For example,in some embodiments, the well treatment composition is added to ordiluted with an aqueous carrier fluid (e.g., water, brine, sea water,fresh water, produced water, reverse osmosis water, or a well-treatmentfluid, such as an acid, a fracturing fluid comprising polymers, producedwater, treated water sand, slickwater, etc.) prior to and/or duringinjection of the well treatment composition into the wellbore.

In some embodiments, the carrier fluid may comprise a brine. Brine is anaqueous solution having total dissolved solids (TDS). As used herein,TDS means the amount of total dissolved solid substances, for examplesalts, in the carrier fluid. Furthermore, TDS typically defines the ioncomposition of the carrier fluid. The TDS is measured in parts permillion (ppm).

EXAMPLES

The following examples are intended to illustrate certain embodiments ofthe present invention, but do not exemplify the full scope of theinvention.

All measurements provided in the following examples were performed usinga capillary suction timer (CST). Capillary suction time (CST) testsmeasure the relative flow capacity of a slurry of ground formation rockused to form an artificial core.

First, 5 g of a 70 mesh grind was placed in 50 ml test fluid and stirredon a magnetic stirrer for 1 hour. Five ml of a slurry of groundformation rock was placed in a cylindrical “mold” setting on top of thechromatography paper. The fluid in the slurry was pulled by capillarypressure into the chromatography paper. A sensor starts the timer whenthe fluid reaches 0.25 in. away from the mold and stops when it reaches1 in. A rock formation sample with dispersible or swelling clays willhave a longer CST time, while the one without clay (or other fineparticles), would have a shorter CST time. Thus, CST tests can be usedto study the relative sensitivity of a rock sample to various fluids.The CST ratio varies from 0.5 (no sensitivity) to upwards of 50 (extremesensitivity).

CST ratio is equal to [CST_(sample)−CST_(blank)]/CST_(blank)], whereCST_(sample) is the time in seconds of the fluid with the rock formationsample and CST_(bank) is the time in seconds of the fluid without therock formation sample.

The higher the CST ratio, indicates a lower performing clay controladditive to prevent clay swelling. The lower the CST ratio, indicates ahigher performing clay control additive.

Example 1

CST measurements were performed using Well Treatment 1, comprising 0.5gpt of clay control 1 (CC1) and 2 gpt of microemulsion 1 (ME1) tominimize clay swelling tendencies. ME1 comprises between about 10 wt %and about 30 wt % surfactant, about 10 wt % and about 60 wt % aqueousphase (e.g. water), and between about 1 wt % and about 20 wt % solvent,versus the total weight of ME1. The surfactant in ME1 comprises benzylcoco alkylbis (hydroxyethyl) chloride ethoxylated alcohol. CC1 comprisesbetween about 20 wt % and about 60 wt % polyquaternary amine polymer,between about 2 wt % and about 10 wt % sodium chloride salt, about 50 wt% aqueous phase (water), of the total weight of CC1. Example 1 used amodel system composition comprising 17 wt % bentonite (montmorillonite)and 83 wt % silica flour, versus the total weight of the model systemcomposition, and shale cuttings from the Niobrara formation of theSouthern Powder River Basin containing 39.6 wt % mixed layers ofsmectite and illite, versus the total weight of the shale cuttings.

TABLE 1 CST ratio Model system composition Shale cuttings Well Treatment1 0.8 1.4 0.5 gpt CC1 and 2 gpt ME1   2 gpt of ME1 22.5 2.7   2 gpt ofCC1 1.17 3.3Table 1 shows the CST ratio measured for Well Treatment 1 (0.5 gpt CC1and 2 gpt ME1), 2 gpt of ME1, 2 gpt of CC1, and 0.5 gpt of CC1, wheneach is used to treat a model system composition and used to treat shalecuttings.

As shown in Table 1, with respect to the model system composition thatwas treated by Well Treatment 1, which has a concentration of CC1 (0.5gpt) that is four times less than the concentration of CC1 used alone (2gpt), exhibited a lower CST ratio (i.e. 0.8) compared to the CST ratioof CC1 when used alone (i.e. 1.17).

As shown in Table 1, with respect to the shale cuttings that weretreated by Well Treatment 1, which has a concentration of CC1 (0.5 gpt)that is four times less than the concentration of CC1 used alone (2gpt), exhibited a lower CST ratio (i.e. 1.4) compared to the CST ratioof CC1 when used alone (i.e. 3.3).

Table 1 shows that the right combination of clay control additive andmicroemulsion can significantly increase clay swelling protection andreduce the amount of clay control needed (e.g. by up to four times less)for optimal protection for both the model system composition and theshale cuttings.

Example 2

CST measurements were performed using Well Treatment 2, comprising 0.5gpt clay control 2 (CC2) and 2 gpt microemulsion 2 (ME2) to reduce orprevent clay swelling tendencies. ME2 comprises between about 10 wt %and about 30 wt % surfactant, between about 10 wt % and about 60 wt %aqueous phase (e.g. water) and between about 1 wt % and about 10 wt %solvent (non-aqueous phase), versus the total weight of ME2. Thesurfactant in ME2 was a mixture comprising about 5 wt % to about 20 wt %of cationic quaternary ammonium and about 5 wt % to about 10 wt % ofethoxylated alcohol.

CC2 comprises between about 2 wt % to about 15 wt % cocohydroxyethylbenzyl quaternary amine and between about 10 wt % to about 20 wt %polyquaternary amine, and about 50 wt % aqueous phase (water), versusthe total weight of CC2. Example 2 used a model system compositioncomprising 17 wt % bentonite (montmorillonite) and 83 wt % silica flour,versus the total weight of the model system composition.

TABLE 2 CST ratio Well Treatment 2 22.16 0.5 gpt CC2 and 2 gpt ME2   2gpt of CC2 8.8   2 gpt of ME2 43Table 2 shows the CST ratio measured for Well Treatment 2 (0.5 gpt CC2and 2 gpt ME2), 2 gpt of CC2, and 2 gpt of ME2.

As shown in Table 2, using 2 gpt of CC2 showed better performance thanusing a combination of 0.5 gpt CC2 and 2 gpt ME2 in preventing clayswelling. In fact, the CST ratio measured for 2 gpt CC2 (i.e. 8.8) wasmuch lower than the one measured for 0.5 gpt CC2 and 2 gpt of ME2 (i.e.22.16). This data shows that not any combination of microemulsion andclay control additive will exhibit a synergistic effect of themicroemulsion and the clay control additive, resulting in the use ofless clay control additive-only the combination of certain clay controladditives and certain microemulsions will enhance clay swellingprotection for the type of rock formation being treated.

Example 3

Example 3, Table 3 and FIG. 1, show the persistency of clay swellingprotection provided by Well Treatment 3 (0.5 gpt CC1 and 2 gpt ME3)compared to CC1 alone and also shows the persistency of clay swellingprotection provided by Well Treatment 4 (0.5 gpt CC3 and 2 gpt ME3)compared to CC3 alone, in reducing or preventing clay swelling afterseveral washes using 500 ppm TDS brine.

A model system composition comprising 17 wt % bentonite (e.g. a swellingclay) and 83 wt % silica flour, versus the total weight of the modelsystem composition, was mixed with 500 ppm TDS brine. The CST ratio wasmeasured and plotted for the model system composition (See FIG. 1,Brine).

CST measurements were performed using Well Treatment 4, comprising 0.5gpt clay control 3 (CC3) and 2 gpt microemulsion 3 (ME3) to reduce orprevent clay swelling tendencies. ME3 comprises between comprisesbetween about 15 wt % and about 30 wt % surfactant, about 10 wt % andabout 50 wt % aqueous phase (e.g. water), and between about 5 wt % andabout 20 wt % solvent, versus the total weight of ME3. The surfactant inME3 comprises a mixture from about 5 wt % to about 15 wt % nonionicethoxylated alcohol, from about 5 wt % to about 15 wt % alkoxylatedpolyimine, and about 5 wt % to about 10 wt % of tristyrylphenolethoxylate. Clay control 3 (CC3) comprises between about 30 wt % andabout 50 wt % polyquaternary ammonium resin, between about 1 wt % andabout 10 wt % sodium chloride (NaCl), and about 40 wt % to about 70 w %of aqueous phase (water), versus the total weight of CC3.

Upon addition of 0.5 gpt of clay control additive CC1 (from Example 1)or CC3, a swelling reversal was observed (i.e. lowering of the CSTratio). CC1 and CC3 were each removed and replaced by the brine (wash)and the persistency of the clay swelling treatment to provide reductionin clay swelling was observed after seven successive washes using thesame brine as they occurred over time.

As shown in Table 3 and FIG. 1 below, Well Treatment 3 (Example 3)showed a lower CST ratio (i.e. 0.67) compared to using CC1 alone (i.e.1.9) and CC3 alone (i.e. 2.1) after treatment. After seven washes usingbrine, the CST ratio for Well Treatment 3 remained constant. However,after only two washes of brine on CC1 or CC3, the CST ratio startedincreasing, which suggests that the CC1 or CC3 was slowly being removedfrom the rock formation sample. This data suggests that Well Treatment 3has a higher persistency in treating swelling clay (i.e. reducing clayswelling) compared to CC1 alone or CC3 alone.

As shown in Table 3 and FIG. 1 below, Well Treatment 4 (Example 3)showed a lower CST ratio (i.e. 0.24) compared to using CC1 alone (i.e.1.9) and CC3 alone (i.e. 2.1) after treatment. After seven washes usingbrine, the CST ratio for Well Treatment 4 remained virtually constant.However, after only two washes of brine on CC1 or CC3, the CST ratiostarted increasing, which suggests that the CC1 or CC3 was slowly beingremoved from the rock formation sample. This data suggests that WellTreatment 4 provided for a higher persistency in treating swelling clay(i.e. reducing clay swelling) compared to CC1 alone or CC3 alone.

TABLE 3 Well Treatment 3 Well Treatment 4 0.5 gpt 0.5 gpt (0.5 gpt CC1and (0.5 gpt CC3 and Brine CC1 CC3 2 gpt ME3) 2 gpt ME3) Untreated 8.2Treated 8.5 1.9 2.1 0.67 0.24 Wash 1 8.9 2.2 2.1 0.71 0.32 Wash 2 9 2.32.4 0.7 0.35 Wash 3 9.1 3.2 3 0.67 0.47 Wash 4 9.3 3.3 3.1 0.66 0.47Wash 5 9.5 3.6 3.8 0.68 0.56 Wash 6 9.8 3.8 3.9 0.78 0.63 Wash 7 9.9 3.84 0.81 0.68

While several embodiments of the present invention have been describedand illustrated herein, those of ordinary skill in the art will readilyenvision a variety of other means and/or structures for performing thefunctions and/or obtaining the results and/or one or more of theadvantages described herein, and each of such variations and/ormodifications is deemed to be within the scope of the present invention.More generally, those skilled in the art will readily appreciate thatall parameters, dimensions, materials, and configurations describedherein are meant to be exemplary and that the actual parameters,dimensions, materials, and/or configurations will depend upon thespecific application or applications for which the teachings of thepresent invention is/are used. Those skilled in the art will recognize,or be able to ascertain using no more than routine experimentation, manyequivalents to the specific embodiments of the invention describedherein. It is, therefore, to be understood that the foregoingembodiments are presented by way of example only and that, within thescope of the appended claims and equivalents thereto, the invention maybe practiced otherwise than as specifically described and claimed. Thepresent invention is directed to each individual feature, system,article, material, and/or method described herein. In addition, anycombination of two or more such features, systems, articles, materials,and/or methods, if such features, systems, articles, materials, and/ormethods are not mutually inconsistent, is included within the scope ofthe present invention.

The indefinite articles “a” and “an,” as used herein in thespecification and in the claims, unless clearly indicated to thecontrary, should be understood to mean “at least one.”

The phrase “and/or,” as used herein in the specification and in theclaims, should be understood to mean “either or both” of the elements soconjoined, i.e., elements that are conjunctively present in some casesand disjunctively present in other cases. Other elements may optionallybe present other than the elements specifically identified by the“and/or” clause, whether related or unrelated to those elementsspecifically identified unless clearly indicated to the contrary. Thus,as a non-limiting example, a reference to “A and/or B,” when used inconjunction with open-ended language such as “comprising” can refer, inone embodiment, to A without B (optionally including elements other thanB); in another embodiment, to B without A (optionally including elementsother than A); in yet another embodiment, to both A and B (optionallyincluding other elements); etc.

As used herein in the specification and in the claims, “or” should beunderstood to have the same meaning as “and/or” as defined above. Forexample, when separating items in a list, “or” or “and/or” shall beinterpreted as being inclusive, i.e., the inclusion of at least one, butalso including more than one, of a number or list of elements, and,optionally, additional unlisted items. Only terms clearly indicated tothe contrary, such as “only one of” or “exactly one of,” or, when usedin the claims, “consisting of,” will refer to the inclusion of exactlyone element of a number or list of elements. In general, the term “or”as used herein shall only be interpreted as indicating exclusivealternatives (i.e. “one or the other but not both”) when preceded byterms of exclusivity, such as “either,” “one of,” “only one of,” or“exactly one of.” “Consisting essentially of,” when used in the claims,shall have its ordinary meaning as used in the field of patent law.

As used herein in the specification and in the claims, the phrase “atleast one,” in reference to a list of one or more elements, should beunderstood to mean at least one element selected from any one or more ofthe elements in the list of elements, but not necessarily including atleast one of each and every element specifically listed within the listof elements and not excluding any combinations of elements in the listof elements. This definition also allows that elements may optionally bepresent other than the elements specifically identified within the listof elements to which the phrase “at least one” refers, whether relatedor unrelated to those elements specifically identified. Thus, as anon-limiting example, “at least one of A and B” (or, equivalently, “atleast one of A or B,” or, equivalently “at least one of A and/or B”) canrefer, in one embodiment, to at least one, optionally including morethan one, A, with no B present (and optionally including elements otherthan B); in another embodiment, to at least one, optionally includingmore than one, B, with no A present (and optionally including elementsother than A); in yet another embodiment, to at least one, optionallyincluding more than one, A, and at least one, optionally including morethan one, B (and optionally including other elements); etc.

Some embodiments may be embodied as a method, of which various exampleshave been described. The acts performed as part of the methods may beordered in any suitable way. Accordingly, embodiments may be constructedin which acts are performed in an order different than illustrated,which may include different (e.g., more or less) acts than those thatare described, and/or that may involve performing some actssimultaneously, even though the acts are shown as being performedsequentially in the embodiments specifically described above.

Use of ordinal terms such as “first,” “second,” “third,” etc., in theclaims to modify a claim element does not by itself connote anypriority, precedence, or order of one claim element over another or thetemporal order in which acts of a method are performed, but are usedmerely as labels to distinguish one claim element having a certain namefrom another element having a same name (but for use of the ordinalterm) to distinguish the claim elements.

In the claims, as well as in the specification above, all transitionalphrases such as “comprising,” “including,” “carrying,” “having,”“containing,” “involving,” “holding,” and the like are to be understoodto be open-ended, i.e., to mean including but not limited to. Only thetransitional phrases “consisting of” and “consisting essentially of”shall be closed or semi-closed transitional phrases, respectively, asset forth in the United States Patent Office Manual of Patent ExaminingProcedures, Section 2111.03.

1. A method of treating a subterranean formation of an oil and/or gaswell using a well treatment composition for clay control treatment,comprising the steps of: injecting a carrier fluid and the welltreatment composition into the subterranean formation, the welltreatment composition comprising: a microemulsion from 75 wt % to 90 wt% versus the total weight of the well treatment composition, wherein themicroemulsion comprises an aqueous phase from 10 wt % to 50 wt %, versusthe total weight of the microemulsion; a cationic surfactant from 10 wt% to 40 wt %, versus the total weight of the microemulsion; and asolvent from 5 wt % and 25 wt %, versus the total weight of themicroemulsion, wherein the solvent is a terpene solvent; and a claycontrol additive from 10 wt % to 25 wt % versus the total weight of thewell treatment composition, wherein the clay control additive compriseswater from 30 wt % to 90 wt %, versus the total weight of the claycontrol additive; a clay control compound from 10 wt % to 70 wt %,versus the total weight of the clay control additive, wherein the claycontrol compound comprises a cationic polymer, and wherein the cationicpolymer comprises a polyquaternary ammonium resin having a molecularweight of less than 5,000 amu; wherein the microemulsion concentrationis from 0.5 gpt to 4.0 gpt of the carrier fluid and the clay controladditive concentration is from 0.25 gpt to 2.0 gpt of the carrier fluid,and reducing swelling of a swelling clay.
 2. The method of claim 1,wherein the injecting the carrier fluid and the well treatmentcomposition into the subterranean formation enhances persistency of theclay control treatment in the reducing swelling of the swelling clay. 3.The method of claim 1, wherein the clay control additive concentrationof the well treatment composition is up to four times less when comparedto a concentration of the clay control additive alone when injected intothe subterranean formation to achieve the same or a higher degree of thereducing swelling of the swelling clay.
 4. The method of claim 1,wherein the clay control additive of the well treatment compositionproduces less damage to the subterranean formation when compared to useof the clay control additive alone when injected into the subterraneanformation to achieve same or higher degree of the reducing swelling ofthe swelling clay.
 5. The method of claim 1, wherein the microemulsionconcentration is 2.0 gpt of the carrier fluid.
 6. The method of claim 1,wherein the clay control additive concentration is 0.5 gpt of thecarrier fluid.
 7. The method of claim 1, wherein the cationic surfactantcomprises a cocohydroxyethyl benzyl quaternary amine.
 8. The method ofclaim 1, wherein the terpene solvent comprises d-limonene, nopol, alphaterpineol, eucalyptol, dipentene, linalool, pinene, alpha-pinene,beta-pinene, alpha-terpinene, or combinations thereof.
 9. A method oftreating a subterranean formation of an oil and/or gas well using a welltreatment composition for clay control treatment, comprising the stepsof: injecting a carrier fluid and the well treatment composition intothe subterranean formation, the well treatment composition comprising: amicroemulsion from 75 wt % to 90 wt % versus the total weight of thewell treatment composition, wherein the microemulsion comprises anaqueous phase from 10 wt % to 50 wt %, versus the total weight of themicroemulsion; a nonionic surfactant from 10 wt % to 40 wt %, versus thetotal weight of the microemulsion; and a solvent from 5 wt % and 25 wt%, versus the total weight of the microemulsion, wherein the solvent isa terpene solvent; and a clay control additive from 10 wt % to 25 wt %versus the total weight of the well treatment composition, wherein theclay control additive comprises water from 30 wt % to 90 wt %, versusthe total weight of the clay control additive; a clay control compoundfrom 10 wt % to 70 wt %, versus the total weight of the clay controladditive, wherein the clay control compound comprises a cationicpolymer, wherein the cationic polymer comprises a polyquaternaryammonium resin having a molecular weight of less than 5,000 amu; whereinthe microemulsion concentration is from 0.5 gpt to 4.0 gpt of thecarrier fluid and the clay control additive concentration is from 0.25gpt to 2.0 gpt of the carrier fluid, and reducing swelling of a swellingclay.
 10. The method of claim 9, wherein the injecting the carrier fluidand the well treatment composition into the subterranean formationenhances persistency of the clay control treatment in the reducingswelling of the swelling clay.
 11. The method of claim 9, wherein theclay control additive concentration of the well treatment composition isup to four times less when compared to a concentration of the claycontrol additive alone when injected into the subterranean formation toachieve the same or a higher degree of the reducing swelling of theswelling clay.
 12. The method of claim 9, wherein the clay controladditive of the well treatment composition produces less damage to thesubterranean formation when compared to use of the clay control additivealone when injected into the subterranean formation to achieve the sameor a higher degree of the reducing swelling of the swelling clay. 13.The method of claim 9, wherein the microemulsion concentration is 2.0gpt of the carrier fluid.
 14. The method of claim 9, wherein the claycontrol additive concentration is 0.5 gpt of the carrier fluid.
 15. Themethod of claim 9, wherein the nonionic surfactant comprises a C₁₂-C₁₅E₇ alcohol ethoxylate, a tristyrlphenol ethoxylate, an alkoxylatedpolyimine, or combinations thereof.
 16. The method of claim 9, whereinthe terpene solvent comprises d-limonene, nopol, alpha terpineol,eucalyptol, dipentene, linalool, pinene, alpha-pinene, beta-pinene,alpha-terpinene, or combinations thereof.
 17. The method of claim 1,wherein the microemulsion comprises a second surfactant comprising anonionic surfactant.
 18. The method of claim 17, wherein the nonionicsurfactant comprises a C₁₂-C₁₅ E₇ alcohol ethoxylate, a tristyrlphenolethoxylate, an alkoxylated polyimine, or combinations thereof.
 19. Themethod of claim 9, wherein the microemulsion comprises a secondsurfactant comprising a cationic surfactant.
 20. The method of claim 19,wherein the cationic surfactant comprises a cocohydroxyethyl benzylquaternary amine.